HALLWOOD ENERGY PARTNERS LP, S-3/A, 1997-12-18

HALLWOOD ENERGY PARTNERS LP
S-3/A, 1997-12-18
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

As filed with the Securities and Exchange Commission on December 18, 1997
REGISTRATION NO. 333-38973
================================================================================

U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------

AMENDMENT NO. 1
TO

FORM S-3
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
--------------------
HALLWOOD ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

<TABLE>
<CAPTION>
DELAWARE 1311 84-0987088
(State or other jurisdiction of (Primary industrial (I.R.S. Employer
incorporation or organization) classification code number) Identification No.)
<S> <C> <C>
CATHLEEN M. OSBORN
GENERAL COUNSEL
HALLWOOD ENERGY PARTNERS, L.P. HALLWOOD ENERGY PARTNERS, L.P.
4582 SOUTH ULSTER STREET PARKWAY, SUITE 1700 4582 SOUTH ULSTER STREET PARKWAY, SUITE 1700
DENVER, COLORADO 80237 DENVER, COLORADO 80237
(303) 850-7373 (303) 850-7373
(Address, including zip code, and telephone number, (Name, address, including zip code,
including area code, of registrant's principal and telephone number, including
executive offices and principal executive offices) area code, of agent for service)
-------------------------------
Copies to:

W. ALAN KAILER JAY H. HEBERT
JENKENS & GILCHRIST, A PROFESSIONAL CORPORATION VINSON & ELKINS L.L.P.
1445 ROSS AVENUE, SUITE 3200 2001 ROSS AVENUE, SUITE 3700
DALLAS, TEXAS 75202 DALLAS, TEXAS 75201
--------------------
</TABLE>

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after the effective date of this Registration Statement.
--------------------

If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [ ]

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, please check the following box. [ ]

If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ X ]

--------------------
CALCULATION OF REGISTRATION FEE

<TABLE>
<CAPTION>
======================================================================================================================
TITLE OF EACH PROPOSED MAXIMUM PROPOSED MAXIMUM
CLASS OF SECURITIES AMOUNT TO BE OFFERING PRICE PER AGGREGATE OFFERING AMOUNT OF
TO BE REGISTERED REGISTERED(1) UNIT (2) PRICE(2) REGISTRATION FEE
- -------------------------------- -------------------- ----------------------- ---------------------- ----------------
<S> <C> <C> <C> <C>
CLASS C UNITS OF LIMITED 2,875,000 UNITS $11.375 $32,703,125 $9,647.42
PARTNER INTERESTS
=====================================================================================================================
</TABLE>

(1) Includes Class C units that may be purchased by the Underwriters to cover
over-allotments, if any.

(2) Estimated solely for the purpose of calculating the
registration fee pursuant to Rule 457.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THIS REGISTRATION STATEMENT
SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO
SECTION 8(a), MAY DETERMINE.
================================================================================

<PAGE> 2

Information contained herein is subject to completion or amendment. A
registration statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold, nor may
offers to buy be accepted, prior to the time the registration statement becomes
effective. This Prospectus shall not constitute an offer to sell or the
solicitation of an offer to buy, nor shall there be any sale of these
securities, in any state in which such offer, solicitation or sale would be
unlawful prior to registration or qualification under the securities laws of any
such state.

PROSPECTUS Subject to completion, dated December ___, 1997
December ____, 1997

2,500,000 CLASS C UNITS
OF LIMITED PARTNER INTEREST

HALLWOOD ENERGY PARTNERS, L.P.

The 2,500,000 Class C Units ("Class C Units") of limited partner interest
in Hallwood Energy Partners, L.P., a Delaware limited partnership (the
"Partnership"), offered hereby are being sold by the Partnership. The Class C
Units are traded on the American Stock Exchange under the symbol "HEPC." The
last reported sale price of the Class C Units on the American Stock Exchange on
December 10, 1997 was $11.375 per Class C Unit.

--------------------

SEE "RISK FACTORS" BEGINNING ON PAGE ___ FOR A DISCUSSION OF CERTAIN
FACTORS THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS.

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY
STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY
IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
===============================================================================================================
Price to Underwriting Proceeds to
Public Discount (1) Partnership (2)
- ---------------------------- ------------------------- -------------------------- --------------------------
<S> <C> <C> <C>
Per Class C Unit............ $ $ $
- ---------------------------- ------------------------- -------------------------- --------------------------
Total (3)................... $ $ $
===============================================================================================================
</TABLE>
(1) The Partnership, the Operating Partnerships (as defined herein) and the
General Partner (as defined herein) have agreed to indemnify the
Underwriters against certain liabilities under the Securities Act of 1933
(the "Securities Act"). See "Underwriting."

(2) Before deducting expenses payable by the Partnership estimated to be
$375,000.

(3) The Partnership has granted the Underwriters a 30-day option to purchase
up to an aggregate of 375,000 additional Class C Units solely to cover
over-allotments, if any, at the Price to Public, less Underwriting
Discount. If the Underwriters exercise this option in full, the total
Price to Public, Underwriting Discount and Proceeds to Partnership will be
$__________, $___________ and $_______________, respectively. See
"Underwriting."

The Class C Units are offered by the several Underwriters subject to prior
sale when, as and if delivered to and accepted by the Underwriters and subject
to their right to reject orders in whole or in part. It is expected that
certificates representing such Class C Units will be made available for delivery
at the offices of Principal Financial Securities, Inc. in ____________________
on or about ____________, 1998.

PRINCIPAL FINANCIAL SECURITIES, INC.
LADENBURG THALMANN & CO. INC.
WHEAT FIRST BUTCHER SINGER
FIRST UNION CAPITAL MARKETS CORP.

<PAGE> 3

[MAP SHOWING THE OUTLINES OF THE
PARTNERSHIP'S CORE PRODUCING PROPERTIES: THE GREATER PERMIAN REGION
OF TEXAS AND SOUTHEAST NEW MEXICO, THE GULF COAST REGION OF LOUISIANA AND TEXAS,
AND THE ROCKY MOUNTAIN REGION]

CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN, OR OTHERWISE AFFECT THE PRICE OF THE CLASS C UNITS,
INCLUDING OVER-ALLOTMENT, STABILIZING TRANSACTIONS, SYNDICATE SHORT COVERING
TRANSACTIONS AND PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE
"UNDERWRITING."

<PAGE> 4
TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUMMARY...........................................................1
Hallwood Energy Partners, L.P............................................1
The Offering.............................................................4
Distribution Policy......................................................4
Risk Factors.............................................................4
Summary Historical Consolidated Financial Data ..........................5
Summary Oil and Gas Operating Data.......................................7
Summary Oil and Gas Reserve Data.........................................8
Summary of Material Tax Considerations...................................9

RISK FACTORS................................................................13
Risks Inherent in the Partnership's Business............................13
Risks Inherent in an Investment in the Partnership......................17
Conflicts of Interest and Fiduciary Responsibilities....................19
Tax Risks...............................................................21

PRICE RANGE OF CLASS C UNITS AND DISTRIBUTIONS..............................24

USE OF PROCEEDS.............................................................24

CAPITALIZATION..............................................................25

CASH DISTRIBUTION POLICY....................................................26

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA.............................27

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.....................................29
General.................................................................29
Results of Operations...................................................29
Nine Months Ended September 30, 1997 Compared to Nine
Months Ended September 30, 1996..................................29
1996 Compared to 1995...................................................30
1995 Compared to 1994...................................................32
Liquidity and Capital Resources.........................................33
Distributions ..........................................................34
Unit Option Plan........................................................34
Financing...............................................................35
Natural Gas Balancing...................................................35
Changing Prices and Hedging.............................................36
Inflation...............................................................37
Issues Relating to the Year 2000........................................37
Environmental Considerations............................................37

BUSINESS AND PROPERTIES.....................................................37
Overview................................................................37
Business Strategy.......................................................39
Organization............................................................40
Reserves and Production by Significant Areas and Fields.................41
Capital Expenditures....................................................41
Oil and Gas Reserves....................................................45
Volumes, Sales Prices and Oil and Gas Production Expense................47
Development, Exploration and Acquisition Capital
Expenditures.....................................................47
Productive Oil and Gas Wells............................................48
Oil and Gas Acreage.....................................................48
Drilling Activity.......................................................48
Marketing...............................................................48
Investment in Hallwood Consolidated Resources Corporation...............49
Competition.............................................................50
Regulation..............................................................50
Operating Hazards and Insurance.........................................53
Title to Properties.....................................................53
Employees...............................................................54
Legal Proceedings.......................................................54

MANAGEMENT..................................................................55
General.................................................................55
Directors, Officers and Key Employees...................................55

EXECUTIVE COMPENSATION......................................................57
General.................................................................57
Compensation of Executive Officers .....................................57
Summary Compensation Table..............................................57
Option Grants and Exercises in Last Fiscal Year.........................58
Long-Term Incentive Plan................................................59
Long-term Incentive Plan Awards in Last Fiscal Year.....................59
Director Compensation...................................................60
Compensation Committee Interlocks and Insider Participation.............60

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS .............................62

CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES .......................63
General ................................................................63
Acquisition of Additional Properties and Conduct of
Exploratory Drilling.............................................64
Fiduciary and Other Duties..............................................64

PRINCIPAL UNITHOLDERS.......................................................66

DESCRIPTION OF CLASS C UNITS................................................67
General.................................................................67
Transfer of Class C Units...............................................67
Status as a Limited Partner or Assignee.................................68
Duties and Status of Transfer Agent.....................................68

DESCRIPTION OF THE PARTNERSHIP AGREEMENTS...................................68
Organization and Duration...............................................69
Management..............................................................69
Allocation of Profits and Loses - The Partnership......................70
Allocation of Profits and Losses - HEPO.................................71
Allocation of Profits and Losses - EDPO.................................71
Allocation of Income Tax Items..........................................72
Distributions...........................................................72
Additional Classes or Series of Units; Sales of Other
Securities............................................................72
Amendment of Partnership Agreement and Operating
Partnership Agreements................................................73
Meetings; Voting........................................................74
Indemnification.........................................................74
Limited Liability.......................................................75
Books and Reports.......................................................76
Termination, Dissolution and Liquidation................................76

UNITS ELIGIBLE FOR FUTURE SALE..............................................78

MATERIAL FEDERAL INCOME TAX CONSIDERATIONS..................................78
Opinion of Counsel......................................................78
Tax Classification of the Partnership...................................79
Tax Consequences of the Offering........................................81
General Features of Partnership Taxation................................81
Tax Consequences of the Partnership's Operations........................89
Sale of Units...........................................................95
Uniformity of Units.....................................................97
Other Tax Consequences..................................................97
Administrative Matters.................................................100

INVESTMENT IN THE PARTNERSHIP BY EMPLOYEE BENEFIT PLANS....................102

UNDERWRITING...............................................................103

LEGAL MATTERS..............................................................104

EXPERTS....................................................................104

AVAILABLE INFORMATION......................................................104

DOCUMENTS INCORPORATED BY REFERENCE........................................105

GLOSSARY OF CERTAIN TERMS..................................................106

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA...................................................................F-1

</TABLE>

<PAGE> 5

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information and financial and operating data appearing elsewhere in this
Prospectus. As used in this Prospectus, unless the context otherwise requires,
the "Partnership" or "HEP" refers to Hallwood Energy Partners, L.P. and its
predecessors, together with its subsidiaries. Unless otherwise indicated, all
information in this Prospectus assumes that the over-allotment option granted to
the Underwriters by the Partnership is not exercised. For ease of reference, a
Glossary of certain terms used in this Prospectus is included under "Glossary of
Certain Terms."

HALLWOOD ENERGY PARTNERS, L.P.

OVERVIEW

Hallwood Energy Partners, L.P. explores for, develops, acquires and
produces oil and gas in the continental United States. The Partnership owns a
diversified portfolio of core producing properties located primarily in the
Greater Permian Region of Texas and Southeast New Mexico, the Gulf Coast Region
of Louisiana and Texas, and the Rocky Mountain Region. During 1996, the
Partnership's total production was 18.6 Bcfe, which consisted of 69% natural gas
and 31% crude oil. At December 31, 1996, the Partnership's estimated proved
reserves were 133.7 Bcfe, approximately two-thirds of which was natural gas,
with a standardized measure of discounted future net cash flows of $206 million.
The Partnership also holds a 46% interest in Hallwood Consolidated Resources
Corporation ("HCRC"), a publicly traded (NMS:HCRC) exploration and production
corporation. As of December 10, 1997, the Partnership's investment in HCRC had a
market value of $33.3 million.

HEP is organized as a limited partnership to achieve more tax efficient
pass through of cash flow to its partners. The Partnership utilizes operating
cash flow, first, to reinvest in operations to maintain its reserve base and
production; second, to make stable cash distributions to Unitholders; and third,
to grow the Partnership's reserve base over time. HEP has three classes of Units
outstanding, designated Classes A, B and C. Class C Units, the class of Units
being offered by this Prospectus, represent preferred limited partner interests
and are traded on the American Stock Exchange (AMEX:HEPC). Class C Unitholders
are paid a preferred distribution of $1.00 per Class C Unit per year before
distributions are paid to other limited partners and are entitled to
preferential distributions upon liquidation of the Partnership. It is the
Partnership's intention to maintain the Class C Unit distributions at $1.00 per
Class C Unit per year to the extent consistent with maintaining its reserve base
and production. At $11.375, the closing market price of the Class C Units on the
American Stock Exchange on December 10, 1997, the Class C Units had an indicated
pre-tax yield of 8.8%. Class A and Class B Units are entitled to distributions
in the amount declared from time to time by the General Partner. During 1997,
Class A Unitholders received distributions of $0.52 and Class B Unitholders
received no distributions. All three classes of Units vote as separate classes
on all matters submitted to Unitholders.

The Partnership has no employees. Management, technical and operational
services are provided by Hallwood Petroleum, Inc. ("HPI"), a subsidiary of the
Partnership. At December 31, 1996, HPI operated on behalf of the Partnership
over 1,000 wells, accounting for approximately 89% of the Partnership's proved
reserves. Management and employees of HPI have extensive experience and
expertise in operational, financial and managerial aspects of the oil and gas
industry. HPI's strengths include conducting cost-efficient operations;
geological and geophysical interpretation and prospect generation; use of
sophisticated land, legal, accounting and tax systems; use of risk management
tools, including price hedges, interest rate swaps and joint ventures; and
experience in making complex acquisitions on favorable terms. In addition,
financial incentive programs reward key operating and field personnel for
minimizing capital costs, operating costs, general and administrative expenses
and well downtime. In 1996, as a result of management's emphasis on cost
control, combined lease operating and general and administrative costs were $.86
per Mcfe produced, with realized gross operating margins of $1.73 per Mcfe.

<PAGE> 6

$.64 per Mcfe for 1996, 1995, and 1994, respectively. From January 1, 1996
through September 30, 1997, the Partnership had a 60% success rate on its
drilling, workovers and recompletions. For purposes of this determination the
Partnership has classified a well as successful if production casing has been
run for a completion attempt on the well.

The Partnership's future growth will be driven by a combination of
development of existing projects, exploration for new reserves and select
acquisitions. The proceeds of the Offering will be utilized by the Partnership
in 1998 to accelerate the drilling of a portion of its current project inventory
which includes an estimated 67 development well and workover locations, 54 wells
and workovers that may be undertaken depending on the results of future
evaluations and 50 exploration locations which, if successful, could lead to
additional opportunities.

BUSINESS STRATEGY

The Partnership's objective is to provide an attractive return to
Unitholders through a combination of cash distributions and capital
appreciation. The following are key strategic elements utilized to achieve that
objective.

ACCELERATION OF DEVELOPMENT OF EXISTING PROPERTY BASE. The Partnership
intends to use a majority of the proceeds from the Offering to accelerate
development and production from its existing inventory of drilling locations.
The Partnership believes its existing development and workover projects offer
meaningful reserve addition opportunities and provide a base for generating
future cash flow, even without exploration or acquisition successes.

EXPLORATION FOR NEW RESERVES. The Partnership is placing increasing
emphasis on exploration as a source of future growth and has an active
exploration program targeting a wide variety of reserve creation opportunities
in its core areas of operations and in select new areas. The Partnership pursues
a balanced portfolio of exploration prospects where it believes multiple
additional new reserve opportunities could result if a significant discovery
were made. At September 30, 1997, the Partnership had approximately 259,000
gross (73,000 net) undeveloped acres on which it was actively conducting
exploration activities.

UTILIZATION OF RISK MANAGEMENT TECHNIQUES. The Partnership uses a
variety of techniques to reduce its exposure to the risks involved in its oil
and gas activities. The Partnership conducts operations in distinct geographic
areas to gain diversification benefits from geologic settings, local commodity
price differences and local operating characteristics. The Partnership seeks to
reduce risks normally associated with exploration through the use of advanced
technologies, such as 3-D seismic surveys, by spreading projects over various
geologic settings and geographic areas, by balancing exposure to crude oil and
natural gas projects, by balancing potential rewards against evaluated risks and
by participating in projects with other experienced industry partners at working
interest levels appropriate for the Partnership. The Partnership seeks to reduce
its exposure to short-term fluctuations in the price of oil and natural gas and
interest rates by entering into various hedging arrangements.

MAINTAIN LOW-COST OPERATING STRUCTURE. One of the Partnership's
strengths is its ability to implement and maintain a low-cost operating
structure, through its affiliate HPI. As operator, HPI manages all field
activities and thereby exercises greater control over the cost and timing of
exploration, drilling and development activities in order to help improve
project returns. The Partnership focuses on reducing lease operating expenses
(on a per unit of production basis), general and administrative expenses and
drilling and recompletion costs in order to improve project returns.

ACQUISITION OF SELECT PROPERTIES. The Partnership actively seeks to
acquire oil and gas properties that are either complementary to existing
production operations or that it believes will provide significant exploration
opportunities beyond any proved reserves acquired. The Partnership has assembled
an experienced management team which employs a comprehensive interdisciplinary
approach encompassing technical, financial, legal and strategic considerations
in evaluating potential acquisitions of oil and gas properties. The
Partnership's average reserve acquisition cost was $.76 per Mcfe for the three
years ended December 31, 1996.

<PAGE> 7

subsidiary, HPI, for more than 10 years. All personnel have access to and use
modern information systems, operating technologies and equipment to help
maximize production and reliability of the Partnership's operations while
minimizing costs.

CURRENT OPERATIONS

The table set forth below indicates the Partnership's project
inventory at November 30, 1997. The Partnership expects to pursue the majority
of the Planned Development Wells and Workovers and Planned Exploration Wells in
1998. The Partnership's drilling plans are subject to change and it continually
reevaluates and upgrades its prospects throughout the year as new opportunities
are generated. Drilling plans are also subject to change based on rig
availability, title or land arrangements, and changes in expected economics
based on new data; therefore, some of the planned and contingent wells shown
below will not be drilled in 1998 and may not be drilled at all.

PROJECT INVENTORY(1)
--------------------------------------------------------------
PLANNED
DEVELOPMENT WELLS AND WORKOVERS
WELLS AND CONTINGENT UPON PLANNED EXPLORATION
PROJECT NAME WORKOVERS FUTURE EVALUATION(2) WELLS
- ------------ ----------- -------------------- -------------------
GREATER PERMIAN REGION
<S> <C> <C> <C>
Carlsbad/Catclaw 3 4 --
Cross Roads/Oasis -- -- 3
East Keystone 2 3 --
Garden City 2 --
Griffin -- 4 5
Merkle -- -- 25
Spraberry 20 14 --

GULF COAST REGION
Bison -- -- 1
Boca Chica -- -- 1
Giddings 1 2 --
Paul Field 1 -- --

ROCKY MOUNTAIN REGION
Bear Gulch -- -- 1
Douglas Arch 3 13 --
Hudson Ranch -- -- 8
San Juan 1 11 --
Toole County 19 3 --
West Sioux Pass -- -- 1

OTHER
Kansas 15 -- --
Sacramento -- -- 5
-- -- --

TOTAL 67 54 50

</TABLE>

(1) All well counts reflect gross wells. The total net wells are 23 Planned
Development Wells and Workovers, 24 Wells and Workovers Contingent upon
Future Evaluation, and eight Planned Exploration Wells.

(2) These projects are sensitive to factors that cannot be determined with
certainty at this time. These factors include, depending on the project:
the effect of drilling or completion techniques or other factors on
projected production rates; the cost of personnel and equipment; the
availability of drilling equipment in the area; obtaining necessary
permits and licenses for the project; the price of oil and gas; the
projected lease operating expenses; the availability of gas gathering
facilities to the project and the success of prior waterflood pilots in
the area. As a result of these uncertainties, whether the Partnership
will undertake these projects and whether they will be successful are
less certain than for planned wells.

<PAGE> 8

Although the Partnership is currently pursuing each planned or
contingent well as set out in the preceding table, there can be no assurance
that these wells will be drilled at all or within the expected time frame. The
final determination with respect to the drilling of any well will depend upon a
number of factors, including (i) the results of exploration efforts and the
acquisition, review and analysis of seismic and other data, (ii) the
availability of sufficient capital resources to the Partnership and the other
participants for the drilling of the prospects, (iii) the approval of the
prospects by other participants after additional data has been compiled, (iv)
economic and industry conditions at the time of drilling, including prevailing
and anticipated prices for oil and gas and the availability of drilling rigs and
crews, (v) the financial resources and results of operations of the Partnership,
and (vi) obtaining necessary permitting for the prospects. There can be no
assurance that any of the planned or contingent wells identified on the
preceding table will encounter reservoirs of commercially productive oil or gas.
See "Risk Factors--Risks Inherent in the Partnership's Business--Replacement
Risk and Expansions of Reserves" and "--Uncertainty of Reserve Information and
Future Net Revenue Estimates."

THE OFFERING

<TABLE>
<CAPTION>
<S> <C>
Class C Units offered
by the Partnership........................................ 2,500,000 Class C Units (1)
Class C Units to be outstanding
after the Offering....................................... 3,164,063 Class C Units (1)

Use of proceeds........................................... The Partnership intends to use the net proceeds from the
Offering to accelerate the drilling of its project inventory
and, in the interim, to repay a portion of its outstanding
indebtedness under one of its credit facilities. See "Use
of Proceeds."

American Stock Exchange symbol............................ HEPC
</TABLE>

- ----------------------

(1) Excludes 375,000 Class C Units issuable upon exercise of the
Underwriters' over-allotment option. As of December 10, 1997 there were
9,977,254 Class A Units, 143,773 Class B Units and 664,063 Class C
Units outstanding.

DISTRIBUTION POLICY

The Partnership's policy is to maintain stable cash distributions to
its limited partners to the extent consistent with its primary objective of
maintaining its reserve base and production. Class C Unitholders are paid a
preferred distribution of $1.00 per Class C Unit per year before distributions
are paid to other limited partners. At $11.375, the closing market price of the
Class C Units on the American Stock Exchange on December 10, 1997, the Class C
Units had an indicated pre-tax yield of 8.8%. The Partnership anticipates that
taxable income allocable to Class C Units generally will be equal to
distributions to the persons who purchase the Class C Units in this Offering,
although there is no assurance this will always be the case. Since March 1996,
the Partnership has distributed $0.25 per Class C Unit per quarter or $1.00 per
Class C Unit on an annualized basis. Since March 1996, the Partnership has also
distributed $0.13 per Class A Unit per quarter or $0.52 per Class A Unit on an
annualized basis.

RISK FACTORS

Limited partner interests are inherently different from capital stock
of a corporation, although many of the business risks to which the Partnership
will be subject are similar to those that would be faced by a corporation
engaged in a similar business. An investment in the Class C Units offered hereby
will involve substantial risks, including risks associated with the nature of
the interests in the Partnership, certain potential conflicts of interest, risks
inherent in the Partnership's business and tax risks. Prospective purchasers of
the Class C Units should carefully consider the risk factors described beginning
on page 14 in evaluating an investment in the Partnership.

4
<PAGE> 9

SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA

The summary of historical consolidated financial information of the
Partnership for the five years ended December 31, 1996 has been derived from the
Partnership's audited Consolidated Financial Statements and the notes thereto
contained elsewhere in this Prospectus. The data presented for the nine months
ended September 30, 1997 and September 30, 1996 has been derived from the
Partnership's unaudited Consolidated Financial Statements and the notes thereto
contained elsewhere in this Prospectus. The summary historical financial
information is qualified in its entirety and should be read in conjunction with
"Capitalization," "Selected Historical Consolidated Financial Data,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," and the audited and unaudited Consolidated Financial Statements of
the Partnership and the related notes thereto included elsewhere in this
Prospectus.

NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
--------------------- -------------------------------------------------------
1997 1996 1996 1995 1994 1993 1992
---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas operations .................... $ 32,302 $ 37,961 $ 50,644 $ 43,454 $ 43,899 $ 44,106 $ 52,822
Gas marketing and transportation(1) ....... 5,046 7,556
Interest .................................. 328 331 422 326 583 461 352
--------- --------- --------- --------- --------- --------- ---------
32,630 38,292 51,066 43,780 44,482 49,613 60,730
--------- --------- --------- --------- --------- --------- ---------
Expenses:
Oil and gas operations ..................... 8,767 8,930 12,237 12,092 12,907 11,689 14,107
Gas marketing and transportation .......... 4,611 7,900
General and administrative ................ 3,250 3,133 4,540 5,580 5,630 6,812 7,732
Depreciation, depletion and amortization... 8,657 10,554 13,500 15,827 18,168 17,076 18,866
Impairment of oil and gas properties ...... 10,943 7,345
Litigation settlement expense (revenue) ... (240) 230 230 386 3,370 (9,768) 245
--------- --------- --------- --------- --------- --------- ---------
20,434 22,847 30,507 44,828 47,420 30,420 48,850
--------- --------- --------- --------- --------- --------- ---------

Operating income (loss) ............. 12,196 15,445 20,559 (1,048) (2,938) 19,193 11,880
--------- --------- --------- --------- --------- --------- ---------

Interest and other income (expense) ........... (2,315) (3,047) (3,878) (4,245) (3,834) (4,692) (6,512)
Equity in earnings (loss) of HCRC ............. 1,384 1,227 1,768 (2,273) (1,499) 112 732
Minority interest in net income of
affiliates ................................ (1,341) (2,092) (2,723) (1,465) (1,822) (1,549) (2,487)
--------- --------- --------- --------- --------- --------- ---------
(2,247) (3,912) (4,833) (7,983) (7,155) (6,129) (8,267)
--------- --------- --------- --------- --------- --------- ---------

Net income (loss) .......................... $ 9,924 $ 11,533 $ 15,726 $ (9,031) $ (10,093) $ 13,064 $ 3,613
========= ========= ========= ========= ========= ========= =========
CASH FLOW DATA:
Net cash provided by operating activities... $ 18,278 $ 22,748 $ 26,423 $ 18,449 $ 21,575 $ 29,312 $ 29,693
Net cash used in investing activities....... $ (11,563) $ (9,450) $ (12,485) $ (10,737) $ (11,061) $ (2,870) $ (795)
Net cash used in financing activities....... $ (10,486) $ (10,776) $ (13,375) $ (5,144) $ (21,244) $ (27,031) $ (20,693)
OTHER FINANCIAL DATA:
Operating cash flow (2) .................... $ 18,918 $ 22,548 $ 30,269 $ 20,766 $ 19,588 $ 32,871 $ 25,260
Capital expenditures(3) .................... $ 11,572 $ 9,505 $ 13,299 $ 17,768 $ 13,885 $ 15,386 $ 15,079
Distributions per Class C Unit ............ $ 0.75 $ 0.75 $ 1.00
Ratio of Earnings to Fixed Charges and
Class C Distributions .................. 4.05 3.90 4.08 (4) (4) 4.08 1.49

BALANCE SHEET DATA:

Total Assets .............................. $ 124,650 $ 121,093 $ 122,792 $ 125,152 $ 136,281 $ 171,624 $ 186,087
Long-term debt ............................. $ 31,986 $ 31,398 $ 29,461 $ 37,557 $ 25,898 $ 38,010 $ 52,814
Partners' capital .......................... $ 68,441 $ 62,016 $ 64,215 $ 57,572 $ 78,803 $ 98,576 $ 89,779

</TABLE>

5
<PAGE> 10

- ----------------------

(1) The Partnership sold its gas marketing and transportation operations
during 1993.

(2) Operating cash flow represents cash flows from operating activities prior
to changes in assets and liabilities. Management of the Partnership
believes that operating cash flow may provide additional information about
the Partnership's ability to meet its future requirements for debt
service, capital expenditures and working capital. Operating cash flow is
a financial measure commonly used in the oil and gas industry and should
not be considered in isolation or as a substitute for net income,
operating income, cash flows from operating activities or any other
measure of financial performance presented in accordance with generally
accepted accounting principles or as a measure of a company's
profitability or liquidity. Because operating cash flow excludes changes
in assets and liabilities and these measures may vary among companies, the
operating cash flow data presented above may not be comparable to
similarly titled measures of other companies or partnerships.

(3) Consists of costs incurred by the Partnership in connection with property
acquisition, exploration and development. See Note 2 to the Partnership's
December 31, 1996 Consolidated Financial Statements included elsewhere in
this Prospectus.

(4) The Partnership had a loss in these years. Interest expense was
$3,956,000 in 1995 and $3,445,000 in 1994.

<PAGE> 11

SUMMARY OIL AND GAS OPERATING DATA

The following table sets forth summary historical production data at the
dates and for the periods indicated.

AS AND FOR THE NINE AS AND FOR THE YEARS ENDED
MONTHS ENDED --------------------------
SEPTEMBER 30,(1) DECEMBER 31,(1)
------------------- ---------------
1997 1996 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil (Mbbls)........................... 581 749 972 993 939
Natural gas (Mmcf).................... 8,588 9,790 12,786 13,035 13,208
Total (Mmcfe)......................... 12,074 14,284 18,618 18,993 18,842

WEIGHTED AVERAGE SALES PRICES(2):
Oil (per Bbl)......................... $ 19.20 $ 19.49 $ 20.10 $ 17.36 $ 16.47
Natural gas (per Mcf)................. $ 2.22 $ 2.18 $ 2.24 $ 1.82 $ 1.97

AVERAGE COST (PER Mcfe):
Production costs(3)................... $ 0.68 $ 0.59 $ 0.62 $ 0.60 $ 0.65
Depreciation, depletion and
amortization(4)..................... $ 0.72 $ 0.74 $ 0.73 $ 0.83 $ 0.96
General and administrative............ $ 0.27 $ 0.22 $ 0.24 $ 0.29 $ 0.30
- -----------------------

</TABLE>

(1) Excludes pro rata production attributable to the Partnership's 46% equity
interest in HCRC. See "Business and Properties--Investment in Hallwood
Consolidated Resources Corporation."

(2) Includes the effects of hedging.

(3) Includes production taxes.

(4) Excludes impairment of oil and gas properties.

<PAGE> 12

SUMMARY OIL AND GAS RESERVE DATA

The following table sets forth summary reserve data at the dates and for
the periods indicated with respect to the Partnership's estimated historical
proved oil and gas reserves and the estimated future net cash flows attributable
thereto. The reserves have been estimated by HPI's in-house engineers.
Approximately 80% of these reserves have been reviewed by Williamson Petroleum
Consultants, Inc., independent petroleum engineers. Estimates of net proved
reserves and future net revenues from which standardized measure of discounted
future net cash flows is derived are based on year-end prices for oil and gas
held constant (except to the extent a contract provides otherwise) in accordance
with the rules and regulations of the Securities and Exchange Commission ("SEC")
and, except as otherwise indicated, give no effect to federal or state income
taxes otherwise attributable to estimated future net revenues from the sale of
oil and gas. The prices of oil and gas at December 31, 1996, were substantially
higher than the prices used in the previous years to estimate net proved
reserves and future net revenues and substantially higher than average oil and
gas prices received for the period ended September 30, 1997. In addition, there
are numerous uncertainties inherent in estimating quantities of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Partnership. See
"Risk Factors Risks Inherent in the Partnership's Business--Uncertainty of
Reserve Information and Future Net Revenue Estimates" and "Business and
Properties--Oil and Gas Reserves."

FOR YEARS ENDED
DECEMBER 31, (1)
-----------------------------------------
1996 1995 1994
------------- --------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
NET PROVED RESERVES:
Oil (Mbbls)............................................... 7,531 8,098 6,738
Natural gas (Mmcf)........................................ 88,542 83,112 85,585
Total (Mmcfe)............................................. 133,728 131,700 125,413

NET PROVED DEVELOPED RESERVES:
Oil (Mbbls)............................................... 7,056 7,444 6,166
Natural gas (Mmcf)........................................ 85,848 77,378 79,699
Total (Mmcfe)............................................. 128,184 122,042 116,695

ESTIMATED FUTURE NET CASH FLOWS(2)................................... $ 334,000 $ 187,000 $ 153,000
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS(2)(3)....... $ 206,000 $ 124,000 $ 104,000

</TABLE>

- ----------------

(1) Excludes pro rata proved reserves attributable to the Partnership's 46%
equity interest in HCRC. See "Business and Properties--Investment in
Hallwood Consolidated Resources Corporation."

(2) The weighted average sales prices used as of December 31, 1996 were $24.18
per Bbl of oil and $3.76 per Mcf of natural gas (which give effect to
hedging). The weighted average sales prices used as of December 31, 1995
were $17.95 per Bbl of oil and $2.03 per Mcf of natural gas; and as of
December 31, 1994 the weighted average sales prices used were $15.80 per
Bbl of oil and $1.72 per Mcf of natural gas.

(3) The standardized measure of discounted future net cash flows prepared by
the Partnership represents the present value (using an annual discount
rate of 10%) of estimated future net revenues from the production of
proved reserves. No effect is given to income taxes as the Partnership is
not a taxpayer.

<PAGE> 13

SUMMARY OF MATERIAL TAX CONSIDERATIONS

The tax consequences of an investment in the Partnership to a particular
investor will depend in part on the investor's own tax circumstances. Each
prospective investor should consult his own tax advisor about the federal, state
and local tax consequences of an investment in Class C Units.

The following is a brief summary of certain material tax considerations of
owning and disposing of Class C Units. Jenkens & Gilchrist, a Professional
Corporation, counsel to the General Partner and the Partnership ("Counsel") is
of the opinion that under existing law, based upon factual representations made
by HEP and HEP's General Partner and assuming the facts described in this
Prospectus are correct, this summary of federal income tax law is correct. This
summary is qualified by the discussion in "Material Federal Income Tax
Considerations," particularly the qualifications on the opinions of Counsel
described therein.

PARTNERSHIP STATUS

In the opinion of Counsel, the Partnership will be classified for federal
income tax purposes as a partnership and will not be taxed as a corporation
under the publicly traded partnership rules of Section 7704 of the Code, and the
beneficial owners of Class C Units generally will be considered partners in the
Partnership. Accordingly, the Partnership will pay no federal income taxes, and
a Class C Unitholder will be required to report in his federal income tax return
his allocable share of the Partnership's income, gains, losses and deductions.
In general, cash distributions to a Class C Unitholder will be taxable only if,
and to the extent that, they exceed the Unitholder's tax basis in his Class C
Units.

PARTNERSHIP ALLOCATIONS

In general, annual income and loss of the Partnership will be allocated 1%
to the General Partner and 99% to the Unitholders for each taxable year. Such
income will be allocated among the Unitholders first to the Class C Unitholders
to the extent of their prior allocable shares of Partnership losses and
deductions, next to the Class C Unitholders to the extent of their aggregate
preference amount whether or not actually distributed, and then to the Class A
and B Unitholders in accordance with their percentage interests. Income or loss
is determined annually and prorated on a monthly basis and apportioned among the
General Partner and the Unitholders of record as of the opening of the first
business day of the month to which it relates, even though Unitholders may
dispose of their Units during the month in question. A Class C Unitholder will
be required to take into account, in determining his federal income tax
liability, his share of income generated by the Partnership for each taxable
year of the Partnership ending within or with the Unitholder's taxable year
whether or not cash distributions are made to a taxpayer. As a consequence, a
Unitholder's share of taxable income of the Partnership (and possibly the income
tax payable by a taxpayer with respect to such income) may exceed the cash, if
any, actually distributed to such Unitholder.

BASIS OF CLASS C UNITS

A Class C Unitholder's initial tax basis in his Class C Unit purchased in
the Offering will be the amount paid for the Class C Unit plus his share of
Partnership nonrecourse liabilities, if any. A Unitholder's basis is generally
increased by his share of Partnership income and any increase in his allocable
share of Partnership nonrecourse liabilities (if any) and decreased by the
amount of any distributions from the Partnership to him and further decreased by
his allocable share of Partnership losses and distributions and any decrease in
his share of Partnership nonrecourse liabilities (if any).

LIMITATIONS ON DEDUCTIBILITY OF PARTNERSHIP LOSSES

In the case of Unitholders subject to the passive loss rules (generally,
individuals and closely-held corporations), any Partnership losses will only be
available to offset future income generated by the Partnership and cannot be
used to offset income from other activities, including passive activities or
investments. Any losses unused by virtue of the passive loss rules may be
deducted when the Unitholder disposes of all of his Units in a fully taxable
transaction with

<PAGE> 14

an unrelated party. In addition, a Unitholder may deduct his share of
Partnership losses only to the extent that losses do not exceed his tax basis in
his Units or, in the case of taxpayers subject to the "at risk" rules (such as
individuals), the amount the Unitholder is at risk with respect to the
Partnership's activities, if less than such tax basis.

SECTION 754 ELECTION

The Partnership has made the election provided for by Section 754 of the
Code, which generally permits a Unitholder to calculate income and deductions by
reference to the portion of his purchase price attributable to each asset of the
Partnership.

DISPOSITION OF CLASS C UNITS

A Unitholder who sells Class C Units will recognize gain or loss equal to
the difference between the amount realized (including his share of Partnership
nonrecourse liabilities, if any) and his adjusted tax basis in such Class C
Units. Thus, prior Partnership distributions in excess of cumulative net taxable
income in respect of a Class C Unit that decrease a Unitholder's tax basis in
such Class C Unit will, in effect, become taxable income if the Class C Unit is
sold at its original cost. A portion of the amount realized from the sale of the
Class C Units (whether or not representing gain) may be taxable as ordinary
income.

OTHER TAX CONSIDERATIONS

In addition to federal income taxes, Unitholders may be subject to other
taxes, such as state and local income taxes, unincorporated business taxes, and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which a Unitholder resides or in which the Partnership does
business or owns property. Although an analysis of those various taxes is not
presented here, each prospective Unitholder should consider their potential
impact on his investment in the Partnership. The Partnership owns property and
conducts business in states that impose a personal income tax. In certain
states, tax losses may not produce a tax benefit in the year incurred (if, for
example, the Partnership has no income from sources within that state) and also
may not be available to offset income in subsequent taxable years. Some of the
states may require the Partnership, or the Partnership may elect, to withhold a
percentage of income from amounts to be distributed to a Unitholder who is not a
resident of the state. Withholding, the amount of which may be more or less than
a particular Unitholder's income tax liability to the state, may not relieve the
nonresident Unitholder from the obligation to file an income tax return. Amounts
withheld may be treated as if distributed to Unitholders for purposes of
determining the amounts distributed by the Partnership. Based on current law and
its estimate of future Partnership operations, the Partnership anticipates that
any amounts required to be withheld will not be material.

It is the responsibility of each prospective Unitholder to investigate the
legal and tax consequences, under the laws of pertinent states and localities,
of his investment in the Partnership. Accordingly, each prospective Unitholder
should consult, and must depend upon, his own tax counsel or other advisor with
regard to those matters. Further, it is the responsibility of each Unitholder to
file all federal, state and local tax returns that may be required of such
Unitholder. Counsel has not rendered an opinion on the state or local tax
consequences of an investment in the Partnership.

OWNERSHIP OF CLASS C UNITS BY TAX-EXEMPT ORGANIZATIONS AND CERTAIN OTHER
INVESTORS

An investment in Class C Units by tax-exempt organizations (including
individual retirement accounts and other retirement plans), regulated investment
companies and foreign persons raises issues unique to such persons. Virtually
all of the Partnership income allocated to a Unitholder that is a tax-exempt
organization will be unrelated business taxable income, and thus will be taxable
to such Unitholder; no significant amount of the Partnership's gross income will
be qualifying income for purposes of determining whether a Unitholder will
qualify as a regulated investment company. Nonresident aliens, foreign
corporations or other foreign persons are not permitted to hold Class C Units.
See "Material Federal Income Tax Considerations--Other Tax
Consequences--Investment by Tax-Exempt Entities."

<PAGE> 15

TAX SHELTER REGISTRATION

The Internal Revenue Code of 1986, as amended (the "Code"), generally
requires that "tax shelters" be registered with the Secretary of the Treasury.
The Partnership is registered as a tax shelter with the IRS. ISSUANCE OF THE
REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE PARTNERSHIP OR
THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.
See "Material Federal Income Tax Considerations--Administrative Matters--Tax
Shelter Registration."

<PAGE> 16

Structure of the Partnership

[GRAPH]

<PAGE> 17

RISK FACTORS

Prospective investors should carefully consider the following risk
factors, in addition to the other information contained in this Prospectus, in
evaluating an investment in the Class C Units offered hereby. This Prospectus
contains certain forward-looking statements. Actual results may vary materially
from those projected in the forward-looking statements as a result of any number
of factors, including the risk factors set forth below.

RISKS INHERENT IN THE PARTNERSHIP'S BUSINESS

Volatility of Oil and Gas Prices

The Partnership's revenues, profitability, future growth and ability to
borrow funds or obtain additional capital, as well as the carrying value of its
properties, are substantially dependent upon prevailing prices of oil and gas.
Historically, the markets for oil and gas have been volatile, and such markets
are likely to continue to be volatile in the future. Prices for oil and gas are
subject to wide fluctuation in response to relatively minor changes in the
supply of and demand for oil and gas, market uncertainty and a variety of
additional factors that are beyond the Partnership's control. These factors
include the level of consumer product demand, weather conditions, domestic and
foreign governmental regulations, the price and availability of alternative
fuels, political conditions in the Middle East, the foreign supply of oil and
gas, the price of foreign imports and overall economic conditions. During 1996,
the high and low prices for oil on the New York Mercantile Exchange ("NYMEX")
were $26.57 per Bbl and $17.45 per Bbl, respectively, and the high and low
prices for natural gas on the NYMEX were $4.57 per Mmbtu and $1.76 per Mmbtu,
respectively. As of December 10, 1997 the price for oil on the NYMEX was $18.13
per Bbl and the price for natural gas on the NYMEX was $2.35 per Mmbtu. It is
impossible to predict future oil and gas price movements with certainty.
Declines in oil and gas prices may materially adversely affect the Partnership's
financial condition, liquidity, ability to finance planned capital expenditures
and results of operations. Lower oil and gas prices also may reduce the amount
of oil and gas that the Partnership can produce economically. See "--Uncertainty
of Reserve Information and Future Net Revenue Estimates"and "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

The Partnership periodically reviews the carrying value of its oil and
gas properties under the full cost accounting rules of the SEC. Under these
rules, capitalized costs of proved oil and gas properties may not exceed the
standardized measure of discounted future net cash flows from proved reserves.
Application of this "ceiling" test generally requires pricing future revenue at
the unescalated prices in effect as of the end of each fiscal quarter and
requires a write down for accounting purposes if the ceiling is exceeded, even
if prices declined for only a short period of time. The Partnership may be
required to write down the carrying value of its oil and gas properties when oil
and natural gas prices are depressed or unusually volatile. If a write down is
required, it would result in a charge to earnings but would not impact cash flow
from operating activities. As a result of the application of this "ceiling"
test, the Partnership had write downs of approximately $10.9 million and $7.4
million in 1995 and 1994, respectively.

Risks of Hedging

In order to reduce its exposure to short-term fluctuations in the prices
of oil and gas, the Partnership periodically enters into hedging arrangements.
The Partnership's hedging arrangements apply to only a portion of its production
and provide only partial price protection against declines in oil and gas
prices. Such hedging arrangements may expose the Partnership to risk of
financial loss in certain circumstances, including instances where production is
less than expected or where the counterparty to any hedging arrangement fails to
perform. In addition, the Partnership's hedging arrangements limit the benefit
to the Partnership of increases in the prices of oil or gas. Total quantities of
oil and gas subject to hedging arrangements during the years ended December 31,
1996, 1995 and 1994 were 300,000 Bbl, 380,000 Bbl and 361,000 Bbl of oil and
5,479 Mmcf, 6,439 Mmcf and 6,461 Mmcf of gas, respectively. The Partnership's
standardized measure of discounted future net cash flows has been decreased by
$20 million at December 31, 1996, due to the effects of hedging contracts. The
Partnership revenues were increased (decreased) by ($2.5 million), $3.5 million
and $1.8 million for the years ended December 31, 1996, 1995 and 1994,
respectively, because of such hedging arrangements. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations --Changing Prices
and Hedging."

Similarly, in order to reduce its exposure to short-term fluctuations in
interest rates and to provide a measure of predictability for a portion of the
Partnership's interest payments under its debt facilities, the Partnership has
entered into contracts to hedge its interest payments on $15 million of its debt
for each of 1997 and 1998 and $10 million for each of 1999 and 2000. Such hedges
apply to only a portion of the Partnership's debt and provide only partial
protection

13
<PAGE> 18

against increases in interest rates. Such hedging arrangements may expose the
Partnership to risk of financial loss in certain circumstances, including
instances where the counterparty to any hedging arrangement fails to perform. In
addition, the Partnership's hedging arrangements limit the benefit to the
Partnership of declines in interest rates. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Financing."

Significant Capital Requirements

Due to its active development, exploration and acquisition programs, the
Partnership has experienced and expects to continue to experience substantial
working capital needs. While the Partnership believes that the net proceeds from
the Offering, cash flow from operations and availability under its existing
credit arrangements should allow the Partnership to successfully implement its
present business strategy, additional financing may be required in the future to
fund the Partnership's growth and developmental and exploratory drilling. No
assurances can be given as to the availability or terms of any such additional
financing that may be required or that financing will continue to be available
under the existing or new credit facilities. In the event sufficient capital
resources are not available to the Partnership, its drilling and other
activities may be curtailed. See "Management's Discussion and Analysis of
Financial Condition and Results of Operation--Liquidity and Capital Resources."

Ability to Manage Growth and Achieve Business Strategy

The Partnership's capital expenditures for oil and gas activities are
expected to be $15.5 million for 1997 and were $13.3 million for 1996, $17.8
million for 1995 and $13.9 million for 1994. The Partnership has not yet
determined its capital expenditure budget for 1998, but management anticipates
that the budget will be approximately the same as 1997. If the Offering is
successfully completed, management anticipates that the Partnership's capital
budget for 1998 will increase by approximately $10 million. The increased budget
may strain the Partnership's technical, operational and administrative
resources. As the Partnership enlarges the number of projects it is evaluating
or in which it is participating, there will be additional demands on the
Partnership's financial, technical, operational and administrative resources.
The Partnership's ability to grow will depend upon a number of factors,
including its ability to identify and acquire new exploratory sites, its ability
to develop existing sites, its ability to continue to retain and attract skilled
personnel, the results of its drilling program, oil and gas prices, access to
capital and other factors. There can be no assurance that the Partnership will
be successful in achieving growth or any other aspect of its business strategy.

Uncertainty of Reserve Information and Future Net Revenue Estimates

There are numerous uncertainties inherent in estimating oil and gas
reserves and their estimated values, including many factors beyond the
Partnership's control. The reserve data set forth in this Prospectus represents
only estimates. Although the Partnership believes the reserve estimates
contained in this Prospectus are reasonable, reserve estimates are imprecise and
are expected to change as additional information becomes available.

Reservoir engineering is a subjective process of estimating underground
accumulation of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies,
and assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom prepared by different engineers, or by the same engineers but
at different times, may vary substantially and such reserve estimates may be
subject to downward or upward adjustment based upon such factors. Actual
production, revenues and expenditures with respect to the Partnership's reserves
will likely vary from estimates and such variances may be material.
See "Business and Properties--Oil and Gas Reserves."

The standardized measure of discounted future net cash flows referred to
in this Prospectus should not be construed as the current market value of the
estimated oil and gas reserves attributable to the Partnership's properties. In
accordance with applicable requirements of the SEC, the estimated discounted
future net cash flows from proved reserves are generally based on prices and
costs as of the date of the estimate, whereas actual future prices and costs may
be materially higher or lower. Actual future net cash flows also will be
affected by factors such as the amount and timing of actual production, supply
and demand for oil and gas, curtailments or increases in consumption by oil and
gas

14
<PAGE> 19

purchasers, and changes in governmental regulations or taxation. The timing of
actual future net cash flows from proved reserves, and thus their actual
standardized measure of discounted future net cash flows, will be affected by
the timing of both the production and the incurrence of expenses in connection
with development and production of oil and gas properties. In addition, the 10%
discount factor, which is required by the SEC to calculate discounted future net
cash flows for reporting purposes, is not necessarily the most appropriate
discount factor based on interest rates in effect from time to time and risks
associated with the Partnership or the oil and gas industry in general.

Replacement and Expansion of Reserves

In general, the volume of production from oil and gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Partnership acquires
properties containing proved reserves or conducts successful exploration and
development activities, or both, the proved reserves of the Partnership will
decline as reserves are produced. The Partnership's future oil and gas
production is, therefore, highly dependent upon its ability to economically
find, develop or acquire additional reserves in commercial quantities. The
business of exploring for, developing or acquiring reserves is
capital-intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Partnership's
ability to make the necessary capital investment to maintain or expand its asset
base of oil and gas reserves would be impaired. In addition, there can be no
assurance that the Partnership's future exploration, development and acquisition
activities will result in additional proved reserves or that the Partnership
will be able to drill productive wells at acceptable costs. Furthermore,
although the Partnership's revenues could increase if prevailing prices for oil
or gas increase significantly, the Partnership's finding and development costs
could also increase. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

Reserve Concentration Risk

The Partnership currently receives approximately 19% of its total
production from its interest in two wells located in the Scott/West Ridge area
of the Gulf Coast region, the A. L. Boudreaux #1 and the G. S. Boudreaux Estate
#1. Both of the wells were shut-in in the second quarter of 1997 while workovers
to plug back several water producing intervals were performed. Additional
workovers may be required if water production rates again increase. Any
interruption in the production from these wells could materially adversely
affect the operations of the Partnership.

Risks of Drilling Activities

The success of the Partnership will be materially dependent upon the
continued success of its drilling program, which will be funded in part with the
proceeds of this Offering. Oil and gas drilling involves numerous risks,
including the risk that no commercially productive oil or gas reservoirs will be
encountered, even if the reserves targeted are classified as proved. The cost of
drilling, completing and operating wells is often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, adverse weather conditions,
compliance with governmental requirements and shortages or delays in the
availability of drilling rigs and the delivery of equipment. The Partnership's
future drilling activities may not be successful and, if drilling activities are
unsuccessful, such failure will have an adverse effect on the Partnership's
future results of operations and financial condition. Although the Partnership
has identified numerous drilling prospects, there can be no assurance that such
prospects will be drilled or that oil or gas will be produced from any such
identified prospects or any other prospects. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

Acquisition Risks

The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and gas prices, operating costs,
potential environmental and other liabilities and other factors. Such
assessments are necessarily inexact and their accuracy inherently uncertain. In
connection with such an assessment, the Partnership performs a review of the
subject properties that it believes to be generally consistent with industry
practices, which generally includes on-site inspections and the review of
reports filed with various regulatory entities. Such a review, however, will not
reveal all existing or potential problems nor will it permit a buyer to become
sufficiently familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every well, and
structural and environmental problems are not necessarily observable even when
an inspection is undertaken. Even when problems are identified, the seller may
be unwilling or unable to provide effective contractual protection against

15
<PAGE> 20

all or part of these problems. There can be no assurances that any acquisition
of property interests by the Partnership will be successful and, if an
acquisition is unsuccessful, that the failure will not have an adverse effect on
the Partnership's future results of operations and financial condition.

Marketability of Production

The marketability of the Partnership's production depends in part upon
the availability, proximity and capacity of gathering systems, pipelines,
trucking or terminal facilities and processing facilities. The Partnership
delivers natural gas through gas gathering systems and gas pipelines, some of
which it does not own. Federal and state regulation of oil and gas production
and transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Partnership's ability
to produce and market its oil and gas. Any dramatic change in market factors
could have a material adverse effect on the Partnership. See "Business and
Properties --Marketing" and " --Regulation."

Operating Hazards and Uninsured Risks

The oil and gas business involves certain operating hazards such as well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pollution, releases of
toxic gas and other environmental hazards and risks, any of which could result
in substantial losses to the Partnership. In addition, the Partnership may be
liable for environmental damages caused by previous owners of property purchased
and leased by the Partnership. As a result, substantial liabilities to third
parties or governmental entities may be incurred, the payment of which could
reduce or eliminate the funds available for exploration, development or
acquisitions or result in the loss of the Partnership's properties. As is common
in the oil and gas industry, the Partnership is not fully insured against the
occurrence of these events either because insurance is not available or because
the Partnership has elected not to insure against their occurrence because of
prohibitive premium costs. The occurrence of an event not fully covered by
insurance could have a material adverse effect on the Partnership's financial
condition and results of operations. See "Business and Properties--Operating
Hazards and Insurance."

Dependence on Key Personnel

The Partnership depends to a large extent on the services of certain key
HPI management personnel, the loss of any of whom could have a material adverse
effect on the Partnership's operations. None of HPI's employees are parties to
employment agreements. The Partnership does not maintain key employee insurance
on any of its employees. The Partnership believes that its success is also
dependent upon HPI's ability to continue to employ and retain skilled technical
personnel.

Government Regulation and Environmental Matters

Oil and gas operations are subject to various federal, state and local
government regulations that may be changed from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties and
taxation. From time to time, regulatory agencies have imposed price controls and
limitations on production by restricting the rate of flow of oil and gas wells
below actual production capacity in order to conserve supplies of oil and gas.
In addition, the development, production, handling, storage, transportation and
disposal of oil and gas, by-products thereof and other substances and materials
produced or used in connection with oil and gas operations are subject to
complex regulation under federal, state and local laws and regulations primarily
relating to protection of human health and the environment. The Partnership is
also subject to changing and extensive tax laws, the effects of which cannot be
predicted. The Partnership believes that it is in substantial compliance with
applicable regulations, although there can be no assurance that this is or will
remain the case. The implementation of new, or the modification of existing,
laws or regulations could have a material adverse effect on the Partnership. No
assurance can be given that existing environmental laws or regulations, as
currently interpreted or reinterpreted in the future, or future laws or
regulations will not materially adversely affect the Partnership's financial
condition and results of operations. See "Business and Properties--Regulation."

<PAGE> 21

Competition

The Partnership encounters competition from other oil and gas companies
in all areas of its operation, including the acquisition of exploratory
prospects and proven properties. The Partnership's competitors include major
integrated oil and gas companies and numerous independent oil and gas companies,
individuals and drilling and income programs. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Partnership's and, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Partnership. Those companies may be able to pay more for exploratory prospects
and productive oil and gas properties, and may be able to define, evaluate, bid
for and purchase a greater number of properties and prospects, than the
Partnership's financial or human resources permit. The Partnership's ability to
explore for oil and gas prospects and to acquire additional properties in the
future will be dependent upon its ability to conduct its operations, to evaluate
and select suitable properties and to consummate transactions in highly
competitive environments. See "Business and Properties--Competition."

Recent Losses

The Partnership has incurred net losses in two of the last five years
of its operations. There can be no assurance that the Partnership will be
profitable in the future. See "Selected Historical Consolidated Financial
Data."

RISKS INHERENT IN AN INVESTMENT IN THE PARTNERSHIP

Cash Distributions Are Not Guaranteed and May Fluctuate with Partnership
Performance

The Partnership's objective is to maintain stable cash distributions to
its Unitholders to the extent consistent with its principal objective of
maintaining its reserve base and production. The Class C Unitholders are
entitled to a distribution of $1.00 per Class C Unit per year before any
distribution may be paid with respect to the Class A Units. Nevertheless, there
can be no assurance regarding the amounts of cash available for distribution.
The actual amounts of cash available for distribution will depend upon numerous
factors, including oil and gas prices, the level and success of the
Partnership's capital expenditures, the level of oil and gas production, debt
service requirements, prevailing economic conditions and financial, business and
other factors, many of which will be beyond the control of the Partnership and
the General Partner. As a result of these and other factors, there can be no
assurance regarding the actual levels of cash distributions to partners by the
Partnership or that such distributions will be equal to a partner's tax
liability on his distributive share of the Partnership's income. See "--Tax
Risks--Tax Liability Exceeding Cash Distributions" and "Cash Distribution
Policy."

The Terms of the Partnership's Indebtedness May Affect the Partnership's
Operations and May Limit its Ability to Make Distributions

The ability of the Partnership to make principal and interest payments
on its Credit Facilities (as defined in the Glossary) depends on future
performance, which is subject to many factors, a number of which will be outside
the Partnership's control. The Partnership's Credit Facilities limit aggregate
distributions paid by the Partnership in any 12- month period to 50% of cash
flow from operations before working capital changes plus 50% of distributions
received from affiliates, if the principal amount of debt of the Partnership is
50% or more of the borrowing base. Aggregate distributions paid by the
Partnership are limited to 65% of cash flow from operations plus 65% of
distributions received from affiliates if the principal amount of debt is less
than 50% of the borrowing base. The Credit Facilities also contain restrictive
covenants that limit the Partnership's ability to incur additional indebtedness.
The payment of principal and interest on such indebtedness will reduce the cash
available to make distributions on the Units. The Partnership's leverage also
may adversely affect the Partnership's ability to finance its future operations
and capital needs, may limit its ability to pursue acquisitions and other
business opportunities and may make its results of operations more susceptible
to adverse economic conditions. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources."

Unitholders Will Have Limited Voting Rights; The General Partner Will
Control the Partnership

The General Partner, through HPI, will manage and control the
Partnership's operations. Unlike the holders of common stock in a corporation,
Unitholders will have only limited voting rights on matters affecting the
Partnership's business. Unitholders will have no right to elect the General
Partner on an annual or other continuing basis. Unitholders

<PAGE> 22

will have limited influence on matters affecting the operation of the
Partnership, and third parties may find it difficult to attempt to gain control
or influence the Partnership's activities. See "Description of the Partnership
Agreements." Because each class of Units votes separately as a class on all
matters on which Unitholders vote, the ownership of 100% of the Class B Units by
The Hallwood Group Incorporated ("Hallwood Group") effectively gives it a veto
right over any matters for which Unitholders vote.

Upon completion of this Offering, the General Partner and its affiliates
will own approximately 5.5% of the outstanding Class C Units (4.9%) if the
Underwriters' over-allotment option is exercised in full), 26% of the Class A
Units and 100% of the Class B Units. As a result, such Unitholders will be able
to influence significantly, and possibly control the outcome of, certain matters
requiring a Unitholder vote. Such ownership of Units may have the effect of
delaying, deferring or preventing a change of control of the Partnership and may
adversely affect the voting and other rights of other Unitholders. See
"Principal Unitholders."

Hallwood Group Has Ability to Veto Any Proposal to Remove General
Partner

The General Partner may be removed only upon the approval of such
removal and the election of a successor general partner by the holders of at
least 662/3% of each class of the outstanding limited partner units (including
limited partner units held by the General Partner and its affiliates). Because
each class of Units votes separately as a class on all matters on which
Unitholders vote, Hallwood Group's ownership of 100% of the Class B Units
effectively gives it a veto right over any proposal to remove the General
Partner.

Existence of Other Provisions that May Discourage a Change of Control in
the Partnership

The Partnership Agreement contains certain other provisions that may
have the effect of discouraging a person or group from attempting to remove the
General Partner or otherwise change the management of the Partnership. The
Partnership has substantial latitude in issuing equity securities without
Unitholder approval. The Partnership Agreement also contains provisions limiting
the ability of Unitholders to call meetings of Unitholders or to acquire
information about the Partnership's operations, as well as other provisions
limiting the Unitholders' ability to influence the manner or direction of
management. The effect of these provisions may be to diminish the price at which
the Class C Units will trade under certain circumstances. See "Description of
The Partnership Agreements--Management."

The Credit Facilities contain provisions relating to a change in
ownership, which if breached and not subsequently cured, may cause the
Partnership to be unable to incur further indebtedness under the Credit
Facilities. There is no restriction on the ability of the General Partner or its
affiliates from entering into a transaction that would trigger such change in
ownership provisions.

On February 6, 1995 the board of directors of the General Partner
approved the adoption of a rights plan ("Rights Plan"), pursuant to which one
right was distributed for each Class A Unit to holders of record at the close of
business on February 17, 1995. The rights trade with the Class A Units. The
rights will become exercisable only in the event, with certain exceptions, that
an acquiring party accumulates 15% or more of the Class A Units, or if a party
announces an offer to acquire 30% or more of the Partnership. The rights will
expire on February 6, 2005. In addition, upon the occurrence of certain events,
holders of the rights will be entitled to purchase, for $24, either Class A
Units or shares in an "acquiring entity," with a market value at that time of
$48. The existence of the Rights Plan could make it more difficult for a party
to gain control of the Partnership and thereby discourage any such attempts to
do so.

The Partnership May Issue Additional Limited Partner Interests, Thereby
Diluting Existing Unitholders' Interests

The Partnership may issue additional Class C Units and other interests
in the Partnership for such consideration and on such terms and conditions as
are established by the General Partner, in its sole discretion, without the
approval of the Unitholders. The Partnership Agreement does not impose any
restriction on the Partnership's ability to issue Partnership securities ranking
senior to the Class C Units at any time. Based on the circumstances of each
case, the issuance of additional Class C Units or securities ranking senior to
or on a parity with the Class C Units may dilute the value of the interests of
the then-existing Class C Unitholders in the Partnership's net assets.
Furthermore, the issuance of Class C Units upon the exercise of the
Underwriters' over-allotment option will increase the total number of Class C
Units outstanding, thereby diluting existing Class C Unitholders' interests in
the Partnership.

<PAGE> 23

Unitholders May Not Have Limited Liability in Certain Circumstances;
Liability for Return of Certain Distributions

The limitations on the liability of holders of limited partner interests
for the obligations of a limited partnership have not been clearly established
in some states. If it were determined that the Partnership had been conducting
business in any state without compliance with the applicable limited partnership
statute, or that the right or the exercise of the right by the Unitholders as a
group to remove the General Partner, to make certain amendments to the
Partnership Agreement or to take other action pursuant to the Partnership
Agreement constituted participation in the "control" of the Partnership's
business, then the Unitholders could be held liable in certain circumstances for
the Partnership's obligations to the same extent as a general partner. In
addition, under certain circumstances a Unitholder may be liable to the
Partnership for the amount of any improper distribution received by such
Unitholder for a period of three years from the date of the distribution. See
"Description of The Partnership Agreements--Limited Liability" for a discussion
of the limitations on liability and the implications thereof to a Unitholder.

Dependence upon Hallwood Petroleum, Inc. for Support Services

Since neither the Partnership nor its General Partner has any employees,
HPI performs all operations on behalf of the Partnership. The Partnership
reimburses HPI at its cost for direct and indirect expenses incurred by HPI for
the benefit of the Partnership and its properties. The indirect expenses for
which HPI is reimbursed include employee compensation, office rent, office
supplies and employee benefits. The General Partner believes that if HPI ceased
providing these services to the Partnership or its affiliates, the costs to the
Partnership of such support services would increase.

Potential Change of Control of the General Partner

There are no restrictions on the ability of Hallwood Group directly or
indirectly to transfer its interest in the General Partner. If Hallwood Group
were to transfer all or part of its interest, a change of control of the General
Partner could occur, and under certain circumstances the General Partner could
be managed by an entity unrelated to Hallwood Group.

CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES

Conflicts of Interest Exist Between the Partnership and the General
Partner and its Affiliates

Certain conflicts of interest exist and may arise in the future as a
result of the General Partner's relationships with its affiliates, on the one
hand, and the Partnership and the Unitholders, on the other hand. Hallwood G.P.,
Inc. ("Hallwood G.P."), a Delaware corporation, as general partner of HEPGP Ltd.
("HEPGP"), a Colorado limited partnership, the General Partner of the
Partnership, has a fiduciary duty to manage the Partnership in a manner that is
in the best interest of the Unitholders. The officers and directors of Hallwood
G.P. also have fiduciary duties to manage the General Partner in the best
interests of HEPGP's partners, Hallwood G.P. and Hallwood Group. In addition,
Messrs. Gumbiner, Troup and Guzzetti are directors and executive officers of
Hallwood Group and, as such, owe a fiduciary duty to the shareholders of
Hallwood Group. Moreover, the officers of Hallwood G.P. and certain of its
directors are also officers or directors of HCRC and, accordingly, owe a
fiduciary duty to the shareholders of HCRC. HCRC participates in oil and gas
projects with the Partnership. Consequently, the duties of Hallwood G.P. and its
officers and directors to the Unitholders of the Partnership may come into
conflict with their duties to other entities or investors. See "Conflicts of
Interest and Fiduciary Responsibilities."

The General Partner May Place Properties Within the Operating
Partnerships that are More Favorable to the General Partner

EDP Operating, Ltd. ("EDPO") and HEP Operating Partnership, L.P.
("HEPO"), (collectively, the "Operating Partnerships") have different provisions
regarding the manner in which the General Partner participates in drilling
within each Operating Partnership. The differences in allocation of costs and
revenues present the General Partner with a conflict of interest in determining
through which of the Operating Partnerships to acquire new drilling locations.
The Board of Directors of Hallwood G.P. has adopted a policy to address this
potential conflict of interest, providing generally that new wells to be drilled
by the Partnership in 14 West Texas counties, other than on properties in which

<PAGE> 24

EDPO HAS an existing interest or that are contiguous to properties in which EDPO
has an existing interest, will be drilled by HEPO through the joint venture with
the General Partner, and that all other new drilling will be done in EDPO.

The General Partner's Affiliates May Compete with the Partnership in
Certain Circumstances

Affiliates of the General Partner (including Hallwood Group and HCRC)
are not prohibited from engaging in any business or activity even if such
activity may be in competition with the Partnership. Hallwood Group does not
presently engage in oil and gas activities other than through its interests in
Hallwood G.P., HEPGP, the Partnership and HCRC. HCRC, however, is actively
engaged in oil and gas production, development and exploration. To minimize the
conflicts of interest between the Partnership and HCRC, the Board of Directors
of each of Hallwood G.P. and HCRC has adopted a policy that each Board will
review annually participation by both the Partnership and HCRC in new oil and
gas properties. Generally, the Partnership and HCRC will participate on a 50/50
basis in all future oil and gas drilling projects, leases, concessions or
acquisitions, unless the activity is inconsistent with either entity's
objectives or the entities already have differing interests in the subject
project. This policy may change, however, if circumstances change or if the
Board of Directors of Hallwood G.P. or HCRC determines it is not in such
entity's best interest.

Contracts Between the Partnership and the General Partner or Its
Affiliates Will Not Be the Result of Arm's-Length Negotiations

Under the terms of the Partnership Agreement, the Partnership is not
restricted from paying the General Partner or its affiliates for any services
rendered, provided such services are rendered on terms that are reasonable to
the Partnership. The Partnership Agreement does not specify who is to determine
whether the terms of transactions are reasonable. In practice, this
determination is made by management, under the supervision of the Board of
Directors of the General Partner. Transactions between the Partnership and the
General Partner and its affiliates will not be the result of arm's-length
negotiations.

Employees of the General Partner's Affiliates Who Provide Services to
the Partnership Will Also Provide Services to Other Businesses

The Partnership will not have any employees and will rely on employees
of HPI to manage the Partnership's affairs. Although the General Partner will
not conduct any other business, Hallwood Group, HCRC and other affiliates of the
General Partner or the Partnership will conduct business and activities of their
own in which the Partnership will have no economic interest and which may also
be conducted by HPI's employees. There may be competing demands among the
Partnership, Hallwood Group, HCRC and such affiliates for the time and efforts
of employees who provide services to more than one of these entities.

The General Partner Is Indemnified and Has Limited Liability

The Partnership is required to indemnify the General Partner, its
affiliates and their respective officers, directors, employees and agents to the
fullest extent permitted by law, against liabilities, costs and expenses
incurred by the General Partner or such other persons, if the General Partner or
such persons acted in good faith and in a manner they reasonably believed to be
in, or not opposed to, the best interests of the Partnership and, with respect
to any criminal proceedings, had no reasonable cause to believe the conduct was
unlawful. In addition, the Partnership Agreement expressly limits the liability
of the General Partner by providing that the General Partner, its affiliates and
their respective officers, directors, employees and agents will not be liable
for monetary damages to the Partnership, the limited partners or assignees for
errors of judgment or for any acts or omissions if the General Partner and such
other persons acted in good faith.

The General Partner Receives Fees for Certain Property Acquisitions

20
<PAGE> 25

related assets on behalf of the Partnership, the General Partner also will
receive 4% of the interests acquired by the Partnership in such assets. Pursuant
to the limited partnership agreements of each of the Operating Partnerships, the
General Partner also directly or indirectly receives an interest in each well
drilled by the Operating Partnerships. The General Partner's interest in the
foregoing fees, as well as differences in rates of return on a cash investment
in a property between the General Partner and the Partnership, may result in
conflicts of interest as to whether the Partnership should engage in any
activity or acquire a property.

TAX RISKS

For a general discussion of the expected federal income tax consequences
of owning and disposing of Class C Units, see "Material Federal Income Tax
Considerations."

Tax Treatment Is Dependent on Partnership Status

The availability to a holder of Class C Units of the federal income tax
benefits of an investment in the Partnership depends, in large part, on the
classification of the Partnership as a partnership for federal income tax
purposes. Based on certain representations made by the General Partner and the
Partnership, Counsel is of the opinion that, under current law, the Partnership
will be classified as a partnership for federal income tax purposes and will not
be taxed as a corporation under the publicly traded partnership rules of Section
7704 of the Code. However, no ruling from the IRS as to such status has been or
will be requested, and the opinion of Counsel is not binding on the IRS.
Moreover, in order for the Partnership to continue to be classified as a
partnership for federal income tax purposes, at least 90% of the Partnership's
gross income for each taxable year must consist of qualifying income. See
"Material Federal Income Tax Considerations--Tax Classification of the
Partnership."

If the Partnership were taxed as a corporation for federal income tax
purposes, the Partnership would pay tax on its income at corporate rates
(currently at a maximum rate of 35%), and no income, gains, losses or deductions
would flow through to the Unitholders. However, distributions would generally be
taxed to the Unitholders as corporate distributions. Moreover, because a tax
would be imposed upon the Partnership as an entity, the cash available for
distribution to the Class C Unitholders would be substantially reduced.
Treatment of the Partnership as an association taxable as a corporation or
otherwise as a taxable entity would result in a material reduction in the
anticipated cash flow and could result in a material reduction in the after-tax
return to the Class C Unitholders. See "Material Federal Income Tax
Considerations--Tax Classification of the Partnership."

There can be no assurance that the law will not be changed so as to
cause the Partnership to be treated as an association taxable as a corporation
for federal income tax purposes or otherwise to be subject to entity-level
taxation.

No IRS Ruling with Respect to Tax Consequences

No ruling has been requested from the IRS with respect to any matter
affecting the Partnership. Accordingly, the IRS may adopt positions that differ
from Counsel's conclusions expressed herein. It may be necessary to resort to
administrative or court proceedings in an effort to sustain some or all of
Counsel's conclusions, and some or all of such conclusions ultimately may not be
sustained. The costs of any contest with the IRS will be borne directly or
indirectly by the Unitholders and the General Partner.

Tax Liability Exceeding Cash Distributions

A Class C Unitholder will be required to pay federal income taxes and,
in certain cases, state and local income taxes on his allocable share of the
Partnership's income, whether or not he receives cash distributions from the
Partnership. No assurance can be given that a Unitholder will receive cash
distributions equal to his allocable share of taxable income from the
Partnership or even the tax liability to him resulting from that income in any
taxable year. Further, a Class C Unitholder may incur a tax liability, in excess
of the amount of cash received, upon the sale of his Class C Units. See
"Material Federal Income Tax Considerations--General Features of Partnership
Taxation--Taxation of Partners" for a discussion of certain state and local tax
considerations that may be relevant to prospective Unitholders.

21
<PAGE> 26

Taxable Income to Tax-Exempt Organizations and Certain Other Investors

Investment in Class C Units by certain tax-exempt entities, regulated
investment companies and foreign persons raises issues unique to such persons.
See "Material Federal Income Tax Considerations--Other Tax
Consequences--Investment by Tax-Exempt Entities." For example, virtually all of
the taxable income derived by most organizations exempt from federal income tax
(including IRAs and other retirement plans) from the ownership of a Class C Unit
may be unrelated business taxable income and thus will be taxable to such a
Unitholder.

Nondeductibility of Losses

In the case of taxpayers subject to the passive loss rules (generally
individuals and closely held corporations), losses generated by the Partnership,
if any, will only be available to offset future income generated by the
Partnership and cannot be used to offset income from other activities, including
passive activities or investments. Passive losses that are not deductible
because they exceed the Unitholder's income generated by the Partnership may be
deducted in full when the Unitholder disposes of all of his Units in a fully
taxable transaction with an unrelated party. Net passive income from the
Partnership may be offset by unused Partnership losses carried over from prior
years, but not by losses from other passive activities, including losses from
other publicly traded partnerships. See "Material Federal Income Tax
Considerations--General Features of Partnership Taxation--Limitations on
Deduction of Losses."

Uniformity of Class C Units and Risks of Nonconforming Depletion,
Depreciation and Amortization Conventions

Because the Partnership cannot match transferors and transferees of
Class C Units, uniformity of the economic and tax characteristics of the Class C
Units to a purchaser of Class C Units must be maintained. To maintain
uniformity, the Partnership has adopted certain depletion, depreciation and
amortization conventions and adjustments that do not conform with all aspects of
certain proposed and final Treasury Regulations. The IRS may challenge those
conventions and adjustments and, if such a challenge were sustained, the
uniformity of Class C Units could be affected. Non- uniformity could adversely
affect the amount of tax depletion, depreciation and amortization available to a
purchaser of Class C Units and could have a negative impact on the value of the
Class C Units. See "Material Federal Income Tax Considerations--Uniformity of
Units."

State, Local and Other Tax Filings and Payments by Unitholders

In addition to federal income taxes, Unitholders will be subject to
other taxes, such as state and local taxes, unincorporated business taxes, and
estate, inheritance or intangible taxes, that may be imposed by the various
jurisdictions in which the Partnership does business or owns property. A
Unitholder may be required to file state and local income tax returns and pay
state and local income taxes in some or all of the various jurisdictions in
which the Partnership does business or owns property, and may be subject to
penalties for failure to comply with those requirements. It is the
responsibility of each Unitholder to file all United States federal, state and
local tax returns that may be required of such Unitholder. Counsel has not
rendered an opinion on the state or local tax consequences of an investment in
the Partnership. See "Material Federal Income Tax Considerations--Other Tax
Consequences--State and Local Taxes."

Tax Shelter Registration; Potential IRS Audit

The Partnership is registered with the IRS as a tax shelter and has been
issued a tax shelter identification number. Issuance of a registration number
does not indicate that this investment or the claimed tax benefits have been
reviewed, examined or approved by the IRS. See "Material Federal Income Tax
Considerations--Administrative Matters--Tax Shelter Registration." No assurance
can be given that the Partnership will not be audited by the IRS or that tax
adjustments will not be made. The rights of a Unitholder owning less than a 1%
profits interest in the Partnership to participate in the income tax audit
process are very limited. Further, any adjustments in the Partnership's returns
will lead to adjustments in the Unitholders' returns and may lead to audits of
Unitholders' returns and adjustments of items unrelated to the Partnership. A
Unitholder would bear the cost of any expenses incurred in connection with an
examination of such Unitholder's personal tax return. See "Material Federal
Income Tax Considerations--Administrative Matters."

Partnership Tax Information and Audits

The Partnership furnishes each partner with a Schedule K-1 that sets
forth his distributive share of income, gains, losses and deductions. In
preparing these schedules, the Partnership uses various accounting and reporting
conventions

22
<PAGE> 27

and adopts various depreciation and amortization methods. There is no assurance
that these schedules will yield a result that conforms to statutory or
regulatory requirements or to administrative pronouncements of the IRS. Further,
the Partnership's tax return may be audited, and any such audit could result in
an audit of a partner's individual tax return as well as increased liabilities
for taxes because of adjustments resulting from the audit.

Counsel Unable to Render an Opinion as to Certain Federal Income Tax
Matters

For the reasons described in "Material Federal Income Tax
Considerations," counsel is unable to render an opinion with respect to the
following specific federal income tax issues: (i) the treatment of a Unitholder
whose Units are loaned to a "short seller;" (ii) whether the Partnership's
allocations of income, gain, loss and deduction with respect to contributed
property and revalued property are consistent with the requirements under
Section 704(c) of the Code; (iii) whether the Partnership's allocations of
depletable basis are consistent with the requirements under Section 613A of the
Code; (iv) whether the Partnership's allocations of income, gain, loss and
deduction have substantial economic effect under Section 704(b) of the Code; (v)
whether the Partnership's method of computing and effecting the depreciation,
depletion and amortization adjustments under Section 743 of the Code is
sustainable; (vi) whether the Partnership's conventions for allocating taxable
income and losses between the transferor and the transferee of Units is
permitted by existing Regulations; and (vii) whether a Unitholder acquiring
Units in separate transactions must maintain a single aggregate adjusted tax
basis in his Units.

<PAGE> 28

PRICE RANGE OF CLASS C UNITS AND DISTRIBUTIONS

On January 17, 1996, the Partnership's Class C Units began trading on
the American Stock Exchange ("AMEX") under the symbol "HEPC." As of September
30, 1997, there were approximately 15,000 holders of record of Class C Units.
The closing price of the Class C Units on the AMEX on December 10, 1997 was
$11.375. The following table sets forth, for the periods indicated, the high and
low reported sales prices for the Class C Units as reported on AMEX and the
distributions paid per Class C Unit for the corresponding periods.

Class C Units High Low Distributions
------------- ---- --- -------------

<S> <C> <C> <C>
First quarter 1996 $7-7/8 $6-1/2 $ .25
Second quarter 1996 8-1/2 7-3/8 .25
Third quarter 1996 9-5/8 8-3/16 .25
Fourth quarter 1996 9-7/8 8-3/4 .25
------
$1.00

First quarter 1997 $7-7/8 $6-1/2 $ .25
Second quarter 1997 9-3/8 8-3/4 .25
Third quarter 1997 10-1/2 8-7/8 .25
Fourth quarter 1997
(through December 10, 1997) 14-1/4 10
</TABLE>

USE OF PROCEEDS

The net proceeds to the Partnership from the sale of the Class C Units
offered hereby are estimated to be $____________ ($_____________ if the
Underwriters' over-allotment option is exercised in full), assuming a public
offering price of $_____ per Class C Unit, after deducting the underwriting
discount and estimated offering expenses.

The Partnership intends to use the net proceeds from the Offering to
accelerate the drilling of a portion of its current project inventory, and, in
the interim, to repay a portion of outstanding indebtedness under its Third
Amended and Restated Credit Agreement (the "Credit Agreement"), which amounts
will then become available to the Partnership under the Credit Agreement. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" for a discussion of the
Partnership's credit facilities.

As of September 30, 1997, $27.7 million was outstanding under the Credit
Agreement. The Credit Agreement matures May 31, 1999. Borrowings under the
Credit Agreement bear interest at the lower of the Certificate of Deposit rate
plus from 1.375% to 1.875%, prime plus 1/2% or the Euro-Dollar rate plus from
1.25% to 1.75%. At September 30, 1997, the applicable interest rate was 7.2%.

<PAGE> 29

CAPITALIZATION

The following table sets forth the historical capitalization of the
Partnership as of September 30, 1997 and the pro forma capitalization of the
Partnership as of September 30, 1997 as adjusted to give effect to the sale by
the Partnership of 2,500,000 Class C Units in connection with the Offering at an
assumed initial price of $____ per Unit. This table should be read in
conjunction with the Consolidated Financial Statements and notes thereto and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere in this Prospectus.

AS OF SEPTEMBER 30, 1997
--------------------------------------
ACTUAL AS ADJUSTED
------ -----------
<S> <C> <C>
DEBT:
Current portion of long-term debt........ $ 0 $ 0
Long-term debt........................... 31,986
--------- ---------
Total Debt....................... 31,986
--------- ---------

PARTNERS' CAPITAL:
Class A Units............................ 65,374 65,374
Class B Subordinated Units............... 1,379 1,379
Class C Units............................ 5,146
General Partner(1)....................... 3,521
Treasury Units........................... (6,979) (6,979)
--------- ---------
Total Partners' Capital.......... 68,441
--------- ---------

Total Capitalization............................. $ 100,427 $
========= =========
</TABLE>

- --------------------------

(1) The Partnership Agreement requires the General Partner to contribute an
amount equal to 1.01% of the capital contributed by limited partners.

<PAGE> 30

CASH DISTRIBUTION POLICY

The Partnership's policy is to maintain stable cash distributions to its
Unitholders to the extent consistent with its principal objective of maintaining
its reserve base and production. Class C Unitholders are paid a preferred
distribution of $1.00 per Class C Unit per year before distributions are paid to
other limited partners. At $11.375, the closing market price of the Class C
Units on the AMEX on December 10, 1997, the Class C Units had an indicated
pre-tax yield of 8.8%. The Partnership anticipates that taxable income allocable
to Class C Units generally will be equal to distributions to the persons who
purchase the Class C Units in this Offering, although there can be no assurance
that this will always be the case. Since March 1996, the Partnership has
distributed $0.25 per Class C Unit per quarter or $1.00 per Class C Unit on an
annualized basis. Since March 1996, the Partnership has also distributed $0.13
per Class A Unit per quarter or $0.52 per Class A Unit on an annualized basis.
The Partnership's Credit Facilities limit aggregate distributions paid by the
Partnership in any 12-month period to 50% of cash flow from operations before
working capital changes plus 50% of distributions received from affiliates, if
the principal amount of debt of the Partnership is 50% or more of the borrowing
base. Aggregate distributions paid by the Partnership are limited to 65% of cash
flow from operations before working capital changes plus 65% of distributions
received from affiliates if the principal amount of debt is less than 50% of the
borrowing base.

Distributions by the Partnership are made within approximately 45 days
after the end of each quarter ending March 31, June 30, September 30 and
December 31, to holders of record on the applicable record date.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The Selected Historical Consolidated Financial Data of the Partnership for
the five years ended December 31, 1996 has been derived from the Partnership's
audited Consolidated Financial Statements and the notes thereto contained
elsewhere in this Prospectus. The data presented for the nine months ended
September 30, 1997 and September 30, 1996 has been derived from the
Partnership's unaudited Consolidated Financial Statements and the notes thereto
contained elsewhere in this Prospectus. The Selected Historical Consolidated
Financial Data is qualified in its entirety and should be read in conjunction
with "Capitalization," "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the audited and unaudited Consolidated
Financial Statements of the Partnership and the related notes thereto included
elsewhere in this Prospectus.

<PAGE> 31

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

Oil and gas operations .................... $ 32,302 $ 37,961 $ 50,644 $ 43,454 $ 43,899 $ 44,106 $ 52,822
Gas marketing and transportation(1) ....... 5,046 7,556
Interest .................................. 328 331 422 326 583 461 352
--------- --------- --------- --------- --------- --------- ---------
32,630 38,292 51,066 43,780 44,482 49,613 60,730
--------- --------- --------- --------- --------- --------- ---------
Expenses:
Oil and gas operations ..................... 8,767 8,930 12,237 12,092 12,907 11,689 14,107
Gas marketing and transportation .......... 4,611 7,900
General and administrative ................ 3,250 3,133 4,540 5,580 5,630 6,812 7,732
Depreciation, depletion and amortization... 8,657 10,554 13,500 15,827 18,168 17,076 18,866
Impairment of oil and gas properties ...... 10,943 7,345
Litigation settlement expense (revenue) ... (240) 230 230 386 3,370 (9,768) 245
--------- --------- --------- --------- --------- --------- ---------
20,434 22,847 30,507 44,828 47,420 30,420 48,850
--------- --------- --------- --------- --------- --------- ---------

Operating income (loss) ............. 12,196 15,445 20,559 (1,048) (2,938) 19,193 11,880
--------- --------- --------- --------- --------- --------- ---------

Net income (loss) .......................... $ 9,924 $ 11,533 $ 15,726 $ (9,031) $ (10,093) $ 13,064 $ 3,613
========= ========= ========= ========= ========= ========= =========
Net income (loss) attributable to General
Partner..................................... $ 1,408 $ 1,923 $ 2,569 $ 1,289 $ 1,631 $ 2,394 $ 1,638

Net income attributable to Class C limited
partners.................................... $ 498 $ 498 $ 664

Net income (loss) attributable to Class A
and Class B limited Partners................ $ 8,018 $ 9,112 $ 12,493 $ (10,320) $ (11,724) $ 10,670 $ 1,975
========= ========= ========= ========= ========= ========= =========
Net income (loss) per class A and Class
B Unit(2)................................... $ .86 $ .99 $ 1.34 $ (1.07) $ (1.20) $ 1.14 $ .24
========= ========= ========= ========= ========= ========= =========
Net income (loss) per Class C Unit............ $ .75 $ .75 $ 1.00

CASH FLOW DATA:
Net cash provided by operating activities... $ 18,278 $ 22,748 $ 26,423 $ 18,449 $ 21,575 $ 29,312 $ 29,693
Net cash used in investing activities....... $ (11,563) $ (9,450) $ (12,485) $ (10,737) $ (11,061) $ (2,870) $ (795)
Net cash used in financing activities....... $ (10,486) $ (10,776) $ (13,375) $ (5,144) $ (21,244) $ (27,031) $ (20,693)

OTHER FINANCIAL DATA:
Operating cash flow (3) .................... $ 18,918 $ 22,548 $ 30,269 $ 20,766 $ 19,588 $ 32,871 $ 25,260
Capital expenditures(4) .................... $ 11,572 $ 9,505 $ 13,299 $ 17,768 $ 13,885 $ 15,386 $ 15,079
Distributions to General Partner............ $ 1,194 $ 1,710 $ 2,243 $ 2,359 $ 2,452 $ 2,168 $ 1,855
Distributions per Class A and Class B
Unit..................................... $ 0.39 $ 0.75 $ 0.52 $ 0.80 $ 0.80 $ 0.80 $ 0.80
Distributions per Class C Unit .............. $ 0.75 $ 0.75 $ 1.00
Ratio of Earnings to Fixed Charges and
Class C Distributions ................... 4.05 3.90 4.08 (5) (5) 4.08 1.49

</TABLE>

27
<PAGE> 32

<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)................... $ (2,875) $ (525) $ (1,355) $ (4,363) $ (9,390) $ 7,020 $ 6,306
Property, plant and equipment, net.......... $ 92,499 $ 87,914 $ 88,549 $ 94,926 $ 107,414 $ 122,133 $ 129,029
Total Assets ............................... $ 124,650 $ 121,093 $ 122,792 $ 125,152 $ 136,281 $ 171,624 $ 186,087
Long-term debt ............................. $ 31,986 $ 31,398 $ 29,461 $ 37,557 $ 25,898 $ 38,010 $ 52,814
Partners' capital .......................... $ 68,441 $ 62,016 $ 64,215 $ 57,572 $ 78,803 $ 98,576 $ 89,779

</TABLE>

- -----------------------
(1) The Partnership sold its gas marketing and transportation operations
during 1993.

(2) As a result of the issuance of Class A Units in connection with a
litigation settlement in 1995, all per Unit information for periods prior
to December 31, 1995 has been retroactively restated. See Note 12 to the
Partnership's December 31, 1996 Consolidated Financial Statements included
elsewhere in this Prospectus.

(3) Operating cash flow represents cash flows from operating activities prior
to changes in assets and liabilities. Management of the Partnership
believes that operating cash flow may provide additional information about
the Partnership's ability to meet its future requirements for debt
service, capital expenditures and working capital. Operating cash flow is
a financial measure commonly used in the oil and gas industry and should
not be considered in isolation or as a substitute for net income,
operating income, cash flows from operating activities or any other
measure of financial performance presented in accordance with generally
accepted accounting principles or as a measure of a company's
profitability or liquidity. Because operating cash flow excludes changes
in assets and liabilities and these measures may vary among companies and
operating cash flow data presented above may not be comparable to
similarly titled measures of other companies or partnerships.

(4) Consists of costs incurred by the Partnership in connection with property
acquisition, exploration and development. See Note 2 to the Partnership's
December 31, 1996 Consolidated Financial Statements included elsewhere in
this Prospectus.

(5) The Partnership had a loss in these years. Interest expense was
$3,956,000 in 1995 and $3,445,000 in 1994.

<PAGE> 33
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

The following management's discussion and analysis of the financial
condition and results of operations of the Partnership should be read in
conjunction with the preceding "Selected Historical Consolidated Financial
Information." Additionally, the Partnership's Consolidated Financial Statements
and the Notes thereto, as well as other data included in this Prospectus, should
be read and analyzed in combination with the analysis below.

GENERAL

HEP began operations in 1985 after it completed an exchange offer in
which it acquired oil and gas interests and operations from a number of oil and
gas partnerships, corporations and individual working interest owners. In 1990,
the Partnership merged with Energy Development Partners, Ltd., another master
limited partnership. HEP is a partnership and therefore, is not subject to
federal income tax. Instead the federal income tax effect of its activities
accrues to its partners. Therefore, no provision for federal income taxes is
included in HEP's financial data.

RESULTS OF OPERATIONS

The following table is presented to contrast the Partnership's
production and weighted average oil and gas prices (in thousands except for
price) for the periods indicated:

FOR THE NINE MONTHS
ENDED SEPTEMBER 30, FOR THE YEARS ENDED DECEMBER 31,
------------------------------------- -------------------------------------------------------------------
1997 1996 1996 1995 1994
------------------ ------------------ ------------------- -------------------- ------------------
OIL GAS OIL GAS OIL GAS OIL GAS OIL GAS
--- --- --- --- --- --- --- --- --- ---
(Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Production.............. 581 8,588 749 9,790 972 12,786 993 13,035 939 13,208
Weighted average
sales price(1)....... $ 19.20 $ 2.22 $ 19.49 $ 2.18 $ 20.10 $ 2.24 $17.36 $ 1.82 $16.47 $ 1.97
</TABLE>

- -----------------
(1) Includes effects of hedging. "See --Changing Prices and Hedging."

NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 1996

OIL AND GAS OPERATIONS REVENUES

Oil and gas operations revenues, which include oil and gas sales as
well as revenue from pipeline, facilities and other, decreased $5,659,000 during
the first nine months of 1997 as compared to the first nine months of 1996. The
decrease was comprised of a 22% decrease in oil production, and a 12% decrease
in gas production. The weighted average sales price for oil and gas was flat
from period to period. Approximately 30% of the decrease in production was due
to the temporary shut-in of the A.L. Boudreaux #1 and G.S. Boudreaux Estate #1
wells for workover, and the remainder was due to normal production declines.

During the second quarter of 1997, management determined that workovers
on the Louisiana wells were necessary because water production had increased to
levels that were unacceptable. The operator performed workovers in August 1997
which successfully plugged back several water producing intervals within the Bol
Mex 3 Zones of both wells. As a result of the workovers, water production on
both wells decreased, and both oil and gas production continued at rates
approximating those prior to the workovers. HEP was not required to pay any
shut-in royalties. Additional workovers may be required if water production
rates again increase.

The effect of the Partnership's hedging transactions was to decrease
the Partnership's weighted average oil prices from $19.56 per Bbl to $19.20 per
Bbl, and weighted average natural gas prices from $2.40 per Mcf to $2.22 per
Mcf, resulting in a $1,755,000 decrease in oil and gas operations revenue for
the first nine months of 1997.

<PAGE> 34

INTEREST REVENUES

Interest income decreased $3,000 for the nine months ended September
30, 1997 compared to the nine months ended September 30, 1996 due to lower
interest rates.

OIL AND GAS OPERATIONS EXPENSE

Oil and gas operations expense decreased $163,000 during the first nine
months of 1997 as compared with the first nine months of 1996, primarily as a
result of a $200,000 decrease in production taxes due to the decrease in oil and
gas production described above, offset by increased maintenance expense.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative expense includes costs incurred for direct
administrative services, such as legal, audit and reserve reports, as well as
allocated internal overhead incurred by HPI on behalf of the Partnership. These
expenses increased $117,000 during the first nine months of 1997 as compared
with the first nine months of 1996, primarily due to a net increase in numerous
miscellaneous items, none of which was individually significant.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE

Depreciation, depletion and amortization expense decreased $1,897,000
during the first nine months of 1997 as compared to the first nine months of
1996. The decrease was primarily the result of a lower depletion rate during
1997 as compared to 1996, due to the decrease in production described above.

LITIGATION SETTLEMENT

Litigation settlement revenues of $240,000 during the first nine months
of 1997 was comprised of insurance proceeds which reimbursed a portion of
expense incurred in a prior period to settle certain litigation. Litigation
settlement expense of $230,000 during the first nine months of 1996 consisted
primarily of expenses incurred to settle a property related lawsuit.

INTEREST AND OTHER INCOME (EXPENSE)

Interest and other income (expense) decreased $732,000 during the first
nine months of 1997 compared to the first nine months of 1996, primarily as
result of lower outstanding debt during 1997.

EQUITY IN EARNINGS (LOSS) OF HCRC

Equity in earnings (loss) of HCRC represents the Partnership's share of
net income attributable to its equity investment in HCRC. The Partnership's
equity in HCRC's earnings increased by $157,000 during the first nine months of
1997 as compared with the first nine months of 1996, primarily due to an
increase in HEP's ownership of HCRC from 40% to 46% during the second quarter of
1996.

Although HCRC and HEP own interests on many of the same properties,
their results of operations do not correspond due to different organizational
structures.

MINORITY INTEREST IN NET INCOME OF AFFILIATES

Minority interest in net income of affiliates decreased $751,000 during
the first nine months of 1997 as compared to the first nine months of 1996, due
to a decrease in the affiliates' oil and gas production and revenues in 1997.

1996 COMPARED TO 1995

OIL AND GAS OPERATIONS REVENUES

Oil and gas operations revenues increased $7,190,000 during 1996 as
compared with 1995. The increase was comprised of a 16% increase in the weighted
average sales price received for oil and a 23% increase in the weighted

<PAGE> 35

average sales price received for natural gas, partially offset by a 2% decrease
in oil and gas production. Property sales accounted for 80% of the decrease in
production and the remainder was due to normal production declines. Also
included in the increase in revenues was a $48,000 increase in revenues from
pipeline, facilities and other.

The effect of the Partnership's hedging transactions was to decrease
the Partnership's weighted average oil prices from $20.85 per Bbl to $20.10 per
Bbl, and weighted average natural gas prices from $2.38 per Mcf to $2.24 per
Mcf, resulting in a $2,519,000 decrease in oil and gas operations revenue for
1996.

INTEREST REVENUES

Interest income increased $96,000 during 1996 compared with 1995, as a
result of a higher average cash balance during 1996 compared with 1995.

OIL AND GAS OPERATIONS EXPENSE

Oil and gas operations expense increased $145,000 during 1996 as
compared with 1995, primarily as a result of increased production taxes due to
the increase in 1996 oil and gas operations revenue discussed above.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative expense decreased $1,040,000 during 1996 as
compared with 1995. Approximately 50% of the decrease is due to a decrease in
performance-based compensation. Approximately 10% of the decrease is due to
lower legal expense in 1996 due to the settlement of a significant lawsuit
during 1995. The remainder is due to a net decrease in numerous miscellaneous
items, none of which is individually significant.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE

Depreciation, depletion and amortization expense decreased $2,327,000
during 1996 as compared with 1995. The decrease was primarily the result of
lower capitalized costs in 1996 as compared with 1995, primarily due to the
property impairments recorded during 1995 and 1994.

IMPAIRMENT OF OIL AND GAS PROPERTIES

Impairment of oil and gas properties during 1995 represents the
impairment of $7,000,000 recorded because capitalized costs at June 30, 1995
exceeded the standardized measure of discounted future net cash flows from
proved oil and gas reserves, based on prices at that date of $16.50 per Bbl of
oil and $1.50 per Mcf of gas, as well as the writeoff of the Partnership's
investment in an Indonesian project of $3,943,000.

LITIGATION SETTLEMENT EXPENSE

Litigation settlement expense during 1996 and 1995 consists primarily
of expenses incurred to settle various individually insignificant claims against
the Partnership.

INTEREST AND OTHER INCOME (EXPENSE)

Interest and other income (expense) decreased $367,000 during 1996
compared to 1995, primarily as a result of lower outstanding debt during 1996.

EQUITY IN EARNINGS (LOSS) OF HCRC

The Partnership's equity in HCRC's earnings increased by $4,041,000
during 1996 as compared with 1995. Approximately $1,360,000 of the increase is
the result of a 6% increase in the Partnership's ownership of HCRC resulting
from the Partnership's purchase of 12,965 shares of HCRC common stock during the
second quarter of 1996. Approximately $2,240,000 of the increase is due to
higher oil and gas prices received by HCRC during 1996, and the remainder of the
increase is due to the inclusion in 1995 of impairment expense resulting from
HCRC's write-off of its investment in an Indonesian project and other property
impairments.

<PAGE> 36

MINORITY INTEREST IN NET INCOME OF AFFILIATES

Minority interest in net income of affiliates increased by $1,258,000
during 1996 as compared to 1995, due to an increase in the affiliates' oil and
gas production and revenues in 1996.

1995 COMPARED TO 1994

OIL AND GAS OPERATIONS REVENUES

Oil and gas operations revenues decreased $445,000 during 1995 as
compared with 1994. The decrease was comprised of an 8% decrease in the weighted
average sales price received for natural gas and a decrease in natural gas
production, partially offset by a 5% increase in the weighted average sales
price received for oil and an increase in oil production. Natural gas production
decreased 1% due to normal production declines. Oil production increased 6% due
to increased production from developmental drilling projects in West Texas,
offset by normal production declines. Also included in the increase in revenues
is a $41,000 increase in revenues from pipeline, facilities and other.

The effect of the Partnership's hedging transactions was to increase
the Partnership's weighted average sales prices for oil from $16.98 per Bbl to
$17.36 per Bbl and weighted average sales prices for natural gas from $1.58 per
Mcf to $1.82 per Mcf, resulting in a $3,505,000 increase in oil and gas
operations revenue for 1995.

INTEREST REVENUES

Interest income decreased $257,000 during 1995 compared with 1994, as a
result of a lower average cash balance during 1995.

OIL AND GAS OPERATIONS EXPENSE

Oil and gas operations expense decreased $815,000 during 1995 as
compared with 1994, primarily as a result of general cost reductions in West
Texas.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative expense decreased $50,000 during 1995 as
compared to 1994.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE

Depreciation, depletion and amortization expense decreased $2,341,000
during 1995 as compared with 1994, primarily as a result of lower capitalized
costs in 1995 as compared with 1994. Such lower capitalized costs were primarily
due to the property impairments recorded during the second quarter of 1995 and
the fourth quarter of 1994.

IMPAIRMENT OF OIL AND GAS PROPERTIES

Impairment expense was $10,943,000 in 1995 and $7,345,000 in 1994.
Impairment of oil and gas properties during 1995 represents the impairment of
$7,000,000 recorded due to the capitalized costs of the Partnership's properties
at June 30, 1995 exceeding the standardized measure of discounted future net
cash flows from proved oil and gas reserves, based on prices at that date of
$16.50 per Bbl of oil and $1.50 per Mcf of natural gas, as well as the write-off
of the Partnership's investment in an Indonesian project of $3,943,000. The
impairment of oil and gas properties during 1994 represents an impairment of
$6,000,000 recorded due to the capitalized costs of the Partnership's properties
at December 31, 1994 exceeding the standardized measure of discounted future net
cash flows from proved oil and gas reserves, based on prices at that date of
$15.80 per Bbl of oil and $1.72 per Mcf of natural gas, as well as the write-off
of certain foreign drilling projects of $1,345,000.

LITIGATION SETTLEMENT

Litigation settlement expense was $386,000 in 1995 as compared to
$3,370,000 in 1994. Litigation settlement expense during 1995 consists primarily
of expenses incurred to settle various individually insignificant claims against
the Partnership. Litigation settlement expense during 1994 represents the
settlement of claims against the Partnership

<PAGE> 37

which are further discussed in Note 13 to the December 31, 1996 Consolidated
Financial Statements included elsewhere in this Prospectus, as well as an amount
paid to settle a claim for royalties on a 1989 take-or-pay settlement.

INTEREST AND OTHER INCOME (EXPENSE)

Interest and other income (expense) increased $411,000 during 1995 as
compared with 1994, due to a higher average outstanding debt balance in 1995.

EQUITY IN EARNINGS (LOSS) OF HCRC

The Partnership's equity in HCRC's loss increased by $774,000 during
1995 as compared to 1994. The increase was primarily due to a $5,000,000
property impairment recorded by HCRC during 1995 as a result of oil and gas
prices, and an additional impairment of $4,277,000 representing the write-off of
HCRC's investment in the Indonesian project, offset by increased revenues during
1995.

MINORITY INTEREST IN NET INCOME OF AFFILIATES

Minority interest in net income of affiliates decreased $357,000 in
1995 compared to 1994, primarily as a result of a decrease in the affiliates'
oil and gas production.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOW

The Partnership generated $18,278,000 of net cash flow from operating
activities in the first nine months of 1997, compared to $22,748,000 in the
first nine months of 1996. The Partnership used the cash flow to meet its
objectives of reserve growth and payment of distributions to partners, as well
as to continue to reduce its debt burden. The Partnership spent $11,572,000 on
property additions, exploration and development, paid distributions to partners
of $5,583,000 and paid down debt in the amount of $3,285,000.

The Partnership generated $26,423,000 of net cash flow from operating
activities in 1996, an increase of 43% over 1995. The increase in cash flow from
operating activities was the result of increased production levels combined with
higher product prices in 1996. The Partnership used the cash flow to meet its
objectives of reserve growth and payment of distributions to partners, as well
as to reduce its debt burden. The Partnership spent $12,615,000 on property
additions and exploration and development costs and received $5,294,000 from the
sale of various properties in 1996. The Partnership paid distributions to
partners of $8,177,000 and had net debt paydowns of $7,088,000, which was
greater than the budgeted paydowns in debt for 1996, including amounts related
to an investment it refinanced in 1996. Investments in affiliates, distributions
paid by consolidated affiliates to minority interests, contract settlement
payments and other financing activities accounted for the remaining $3,275,000
used in investing and financing activities in 1996.

PROPERTY PURCHASES, SALES AND CAPITAL BUDGET

Through September 30, 1997, the Partnership incurred approximately
$11,572,000 for exploration, development and acquisition costs toward the 1997
capital budget of $15,500,000. The expenditures were comprised of approximately
$9,073,000 for exploration and development and approximately $2,499,000 for
property acquisitions.

Through the first nine months of 1997, the Partnership's significant
capital expenditures included approximately $5,750,000 for the drilling of 35
wells, 25 of which were successful, and acreage and data acquisition in the
Greater Permian Region in Texas and Southeast New Mexico; approximately
$2,250,000 on drilling, recompletion or repair of six wells, four of which were
successful, in the Gulf Coast Region in Louisiana and Texas; approximately
$1,700,000 for the drilling and recompletion of 17 wells, 11 of which were
successful, in the Rocky Mountain Region in Colorado, Montana, North Dakota,
Northwest New Mexico and Wyoming; and the remainder on numerous projects in
other areas.

In 1996, the Partnership incurred $12,615,000 in direct property
additions and exploration and development costs, and approximately $441,000 for
the purchase of HCRC shares. The costs were comprised of approximately
$9,467,000 for domestic exploration and development expenditures and
approximately $3,148,000 for property acquisitions. The Partnership's 1996
capital program led to the replacement, through acquisitions and drilling, of
75%

<PAGE> 38

of the equivalent barrels produced during 1996. Overall replacement, including
revisions to prior year reserves, was 145% of 1996 production.

The Partnership's significant direct exploration and development
expenditures in 1996 included approximately $1,359,000 for the drilling of 17
wells, 15 of which were successful, and participation in nine recompletions, six
of which were successful, in the West Texas Kermit area; approximately $435,000
for 3-D seismic data and $160,000 for two exploratory wells, both of which were
dry, in Crane County, Texas; approximately $515,000 for 3-D seismic data and
related acreage and $184,000 for the drilling of eight wells, seven of which
were successful, in the Merkel Project area in Texas; approximately $330,000 for
the drilling of two nonoperated wells, one of which was successful, in North
Dakota; approximately $150,000 for an exploratory dry hole and approximately
$600,000 for an Interlake Formation development well in Montana which was
successful; approximately $505,000 for 11 recompletions and two drilled wells in
Reagan County, Texas, nine of which were successful; and approximately $225,000
for the recompletion of one well in Louisiana which was successful.

Also in 1996, in the San Juan Basin of Colorado and New Mexico, the
Partnership, directly and through an affiliate, acquired interests in 38 coal
bed methane wells for $1,734,000. Nine recompletions, seven of which were
successful, were performed in this area during 1996 for a cost of approximately
$690,000, and numerous other facility projects were completed for approximately
$270,000. In 1996, the Partnership spent approximately $575,000 in New Mexico
for the recompletion of three wells, two of which were successful, and the
drilling of two wells, both of which were successful.

During 1996, the Partnership received $1,300,000 from the sale of its
interests in the Hoople Field in Crosby County, Texas, $3,800,000 from the sale
of its interests in the Bethany Longstreet area of Louisiana and $194,000 from
the sale of various nonstrategic properties.

The Partnership intends to place increased emphasis on exploration as a
source of future growth and has an active exploration program testing a wide
variety of reserve creation opportunities in its core areas of operations and in
select new areas. The Partnership will continue to consider international
projects in 1998, utilizing stringent screening criteria. If this Offering is
successfully completed, the Partnership intends to increase its capital budget
for 1998 by approximately $10 million over the budget for 1997, which increase
will allow the Partnership to participate in an increased number of projects. It
is not possible to predict the outcome of the Partnership's exploration
activities, and there can be no assurance that such projects will be successful.
The Partnership's past performance is not necessarily indicative of its
performance in the future.

DISTRIBUTIONS

On January 19, 1996, the Partnership distributed to the Class A
Unitholders one new Class C Unit for every 15 Class A Units held as of the
record date of December 18, 1995. Pursuant to the regulations of the American
Stock Exchange, Class A Unitholders who sold their Units between December 14,
1995 and January 19, 1996 also sold their right to receive the associated Class
C Unit dividend. Class C Units were created to give the Partnership greater
flexibility in structuring future acquisitions by allowing the Partnership to
issue a security with a fixed distribution rate. Class C Units trade separately
from the Partnership's Class A Units. The Class C Units have a distribution
preference of $1.00 per year, payable quarterly, and distributions on the new
units commenced during the first quarter of 1996. During 1996, the Partnership
made distributions of $.52 per Class A Unit and $1.00 per Class C Unit to its
Unitholders. Through September 30, 1997, the Partnership made distributions of
$.39 per Class A Unit and $.75 per Class C Unit to its Unitholders.

UNIT OPTION PLAN

On January 31, 1995, the board of directors of the General Partner
approved the adoption of the 1995 Unit Option Plan to be used for the motivation
and retention of directors, employees and consultants performing services for
the Partnership. The plan authorizes the issuance of options to purchase 425,000
Class A Units. Grants of options to purchase 425,000 Class A Units were made on
January 31, 1995, and all of these options are currently vested. The

<PAGE> 39

exercise price of each option granted is $5.75 per Class A Unit, which was the
closing price of the Class A Units on January 30, 1995. No options have been
exercised.

During 1996, the Partnership adopted the disclosure provisions of
Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based
Compensation" ("SFAS 123"). SFAS 123 requires entities to use the fair value
method to either account for, or disclose, stock based compensation in their
financial statements. Because the Partnership elected the disclosure provisions
of SFAS 123, the adoption of SFAS 123 did not have a material effect on the
financial position or results of operations of the Partnership.

FINANCING

During the second quarter of 1997, HEP and its lenders amended and
restated HEP's Second Amended and Restated Credit Agreement (as amended, the
"Credit Agreement") to extend the term date of its line of credit to May 31,
1999. Under the Credit Agreement and an Amended and Restated Note Purchase
Agreement ("Note Purchase Agreement") (collectively referred to as the "Credit
Facilities"), HEP's borrowing base is $51,000,000 at September 30, 1997. HEP had
amounts outstanding at September 30, 1997 of $27,700,000 under the Credit
Agreement and $4,286,000 under the Note Purchase Agreement. HEP's borrowing base
is further reduced by an outstanding contract settlement obligation of
$2,690,000; therefore, its unused borrowing base totaled $16,324,000 at
September 30, 1997.

Borrowings under the Note Purchase Agreement bear interest at an annual
rate of 11.85%, which is payable quarterly. Annual principal payments of
$4,286,000 began April 30, 1992, and the debt is required to be paid in full on
April 30, 1998. HEP intends to fund the payment due in April 1998 through
additional borrowings under the Credit Agreement; thus, no portion of HEP's Note
Purchase Agreement is classified as current as of September 30, 1997.

Borrowings against the Credit Agreement bear interest at the lower of
the Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or
the Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was
7.2% at September 30, 1997. Interest is payable monthly, and quarterly principal
payments of $1,874,125, as adjusted for the anticipated borrowings to fund the
Note Purchase Agreement payment due in April 1998, commence May 31, 1999.

The borrowing base for the Credit Facilities is redetermined
semiannually. The Credit Facilities are secured by a first lien on approximately
80% of HEP's oil and gas properties as determined by the lenders. Additionally,
aggregate distributions paid by HEP in any 12 month period are limited to 50% of
cash flow from operations before working capital changes plus 50% of
distributions received from affiliates, if the principal amount of debt of HEP
is 50% or more of the borrowing base. Aggregate distributions paid by HEP are
limited to 65% of cash flow from operations before working capital changes plus
65% of distributions received from affiliates if the principal amount of debt of
HEP is less than 50% of the borrowing base.

HEP entered into contracts to hedge its interest rate payments on
$15,000,000 of its debt for each of 1997 and 1998 and $10,000,000 for each of
1999 and 2000. HEP does not use the hedges for trading purposes, but rather for
the purpose of providing a measure of predictability for a portion of HEP's
interest payments under its Credit Agreement, which has a floating interest
rate. In general, it is HEP's goal to hedge 50% of the principal amount of its
debt for the next two years and 25% for each year of the remaining term of the
debt. HEP has entered into four hedges, one of which is an interest rate collar
pursuant to which it pays a floor rate of 7.55% and a ceiling rate of 9.85%, and
the others are interest rate swaps with fixed rates ranging from 5.75% to 6.57%.
The amounts received or paid upon settlement of these transactions are
recognized as interest expense at the time the interest payments are due.

NATURAL GAS BALANCING

The Partnership uses the sales method for recording its natural gas
balancing. Under this method, the Partnership recognizes revenue on all of its
sales of production, and any over-production or under-production is recovered or
repaid at a future date.

As of December 31, 1996, the Partnership had a net over-produced
position of 166,000 Mcf ($372,000 valued at average annual natural gas prices).
The General Partner believes that this imbalance can be made up from production
on existing wells or from wells that will be drilled as offsets to existing
wells and that this imbalance will not have a material effect on the
Partnership's results of operations, liquidity and capital resources. The
reserves disclosed in Oil

<PAGE> 40

and Gas Reserves elsewhere in this Prospectus have been decreased by 166,000 Mcf
in order to reflect the Partnership's gas balancing position.

CHANGING PRICES AND HEDGING

Prices received for oil and gas production depend upon numerous factors
that are beyond the Partnership's control, including the extent of domestic and
foreign production, imports of foreign oil, market demand, domestic and
worldwide economic and political conditions, and government regulations and tax
laws. See "Risk Factors--Risks Inherent in the Partnership's
Business--Volatility of Oil and Gas Prices." Prices for both oil and gas have
fluctuated significantly from 1994 through 1996. The following table presents
the average prices received per year by the Partnership, and the effects of the
hedging transactions discussed below.

<TABLE>
<CAPTION>
OIL NATURAL GAS
---------------------------------------------------------------------------------
(EXCLUDING EFFECTS (INCLUDING EFFECTS (EXCLUDING EFFECTS (INCLUDING EFFECTS
OF HEDGING OF HEDGING OF HEDGING OF HEDGING
TRANSACTIONS) TRANSACTIONS) TRANSACTIONS) TRANSACTIONS)
------------- ------------- ------------- -------------
(PER BBL) (PER BBL) (PER MCF) (PER MCF)
<S> <C> <C> <C> <C>
First 9 months of 1997 $19.56 $19.20 $2.40 $2.22
1996 20.85 20.10 2.38 2.24
1995 16.98 17.36 1.58 1.82
1994 15.50 16.47 1.90 1.97
</TABLE>

The Partnership has entered into numerous financial contracts to hedge
the prices of its oil and gas. The purpose of the hedges is to provide
protection against price drops and to provide a measure of stability in the
volatile environment of oil and gas spot pricing.

The following table provides a summary of the Partnership's financial
contracts at September 30, 1997:

<TABLE>
<CAPTION>
OIL NATURAL GAS
-------------------------- ---------------------------
PERCENT OF PERCENT OF
PRODUCTION CONTRACT PRODUCTION CONTRACT
PERIOD HEDGED FLOOR PRICE HEDGED FLOOR PRICE
------ ---------- ----------- ---------- -----------
(PER Bbl) (PER Mcf)
<S> <C> <C> <C> <C>
Last 3 months of 1997 48% $17.78 46% $1.97
1998 26% $17.12 46% $2.04
1999 3% $15.88 27% $1.87
2000 0% 16% $2.01
</TABLE>

Certain of the Partnership's financial contracts for oil are
participating hedges whereby the Partnership will receive the contract price if
the posted futures price is lower than the contract price, and will receive the
contract price plus between 25% and 75% of the difference between the contract
price and the posted futures price if the posted futures price is greater than
the contract price. Certain other of the Partnership's financial contracts for
oil are collar agreements whereby the Partnership will receive the contract
price if the spot price is lower than the contract price, the cap price if the
spot price is higher than the cap price, and the spot price if that price is
between the contract price and the cap price. The cap prices range from $17.50
to $19.35 per Bbl.

Certain of the Partnership's financial contracts for natural gas are
collar agreements whereby the Partnership will receive the contract price if the
spot price is lower than the contract price, the cap price if the spot price is
higher than the cap price, and the spot price if that price is between the
contract price and the cap price. The cap prices range from $2.78 to $2.93 per
Mcf.

<PAGE> 41

During the fourth quarter of 1997 through December 10, 1997, the
average oil price (for barrels not hedged) was approximately $18.40 per Bbl, and
the average price of natural gas (for quantities not hedged) was approximately
$2.75 per Mcf.

During 1996, the Partnership adopted Statement of Financial Accounting
Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" ("SFAS 121"). SFAS 121 provides the
standards for accounting for the impairment of various long-lived assets.
Substantially all of the Partnership's long-lived assets consist of oil and gas
properties accounted for using the full cost method of accounting, which
requires an impairment to be recorded when total capitalized costs exceed the
standardized measure of discounted future net cash flows from proved oil and gas
reserves. Therefore, the adoption of SFAS 121 did not have a material effect on
the financial position or results of operations of the Partnership.

INFLATION

Inflation did not have a material impact on the Partnership in 1996 and
is not anticipated to have a material impact in 1997.

ISSUES RELATED TO THE YEAR 2000

As the year 2000 approaches, there are uncertainties concerning whether
computer systems will properly recognize date-sensitive information when the
year changes to 2000. Systems that do not properly recognize such information
could generate erroneous data or fail.

Because of the nature of the oil and gas industry and the necessity for
the Partnership to make reserve estimates and other plans well beyond the year
2000, the Partnership's computer systems and software were already configured to
accommodate dates beyond the year 2000. The Partnership believes that the year
2000 will not pose significant operational problems for the Partnership's
computer systems. The Partnership has not yet completed its assessment of all of
its systems, or the computer systems of third parties with which it deals, and
it is not possible at this time to assess the effect of a third party's
inability to adequately address year 2000 issues.

ENVIRONMENTAL CONSIDERATIONS

The exploration for, and development of, oil and gas involve the
extraction, production and transportation of materials which, under certain
conditions, can be hazardous or can cause environmental pollution problems. In
light of the current interest in environmental matters, the General Partner
cannot predict what effect possible future public or private action may have on
the business of HEP. HEP's historical environmental expenditures have not been
material and are not expected to be material in the future. The General Partner
is continually taking actions it believes are necessary in its operations to
ensure conformity with applicable federal, state and local environmental
regulations, and does not presently anticipate that the compliance with federal,
state and local environmental regulations will have a material adverse effect
upon capital expenditures, earnings, cash flows or the competitive position of
HEP in the oil and gas industry.

BUSINESS AND PROPERTIES

OVERVIEW

<PAGE> 42

Partnership also holds a 46% interest in HCRC, a publicly traded (NMS:HCRC)
exploration and production corporation. As of December 10, 1997, the
Partnership's investment in HCRC had a market value of $33.3 million.

HEP is organized as a limited partnership to achieve more tax efficient
pass through of cash flow to its partners. The Partnership utilizes operating
cash flow, first, to reinvest in operations to maintain reserves and production;
second, to make stable cash distributions to Unitholders; and third, to grow the
Partnership's reserve base over time. HEP has three classes of Units
outstanding, designated Classes A, B and C. Class C Units, the class of units
being offered by this Prospectus, represent preferred limited partner interests
and are traded on the American Stock Exchange (AMEX:HEPC). Class C Unitholders
are paid a preferred distribution of $1.00 per Class C Unit per year before
distributions are paid to other limited partners and are entitled to
preferential distributions upon liquidation of the Partnership. It is the
Partnership's intention to maintain the Class C distributions at $1.00 per Class
C Unit per year to the extent consistent with maintaining its reserve base and
production. At $11.375, the closing market price of the Class C Units on the
AMEX on December 10, 1997, the Class C Units had an indicated pre-tax yield of
8.8%. Class A and Class B Units are entitled to distributions in the amount
declared from time to time by the General Partner. During 1997, Class A
Unitholders received distributions of $0.52 and Class B Unitholders received no
distributions. All three classes of Units vote as separate classes on all
matters submitted to Unitholders. The Partnership's Class A Units of limited
partner interest are also traded on the American Stock Exchange (AMEX:HEP).

The Partnership has no employees. Management, technical and operational
services are provided by HPI, a subsidiary of the Partnership. At December 31,
1996, HPI operated on behalf of the Partnership over 1,000 wells, accounting for
approximately 89% of the Partnership's proved reserves. Management and employees
of HPI have extensive experience and expertise in operational, financial and
managerial aspects of the oil and gas industry. HPI's strengths include
conducting cost-efficient operations; geological and geophysical interpretation
and prospect generation; use of sophisticated land, legal, accounting and tax
systems; use of risk management tools, including price hedges, interest rate
swaps and joint ventures; and experience in making complex acquisitions on
favorable terms. In addition, financial incentive programs reward key operating
and field personnel for minimizing capital costs, operating costs, general and
administrative expenses and well downtime. In 1996, as a result of management's
emphasis on cost control, combined lease operating and general and
administrative costs were $.86 per Mcfe produced, with realized gross operating
margins of $1.73 per Mcfe.

As operator, HPI is able to exert greater control over the cost and
timing of all field activities. HPI diligently manages the Partnership's
producing properties to maximize economic production over the life of the
properties through a combination of development well drilling, existing well
recompletions and workovers and enhanced recovery operations. The Partnership
uses advanced drilling technologies to minimize costs and frequently performs
operational reviews to minimize operating expenses.

The Partnership has an active exploration program targeting a wide
variety of reserve creation opportunities. In its exploration and development
projects, geoscientists integrate 3-D seismic, 2-D seismic and all available
subsurface well control data on geologic and geophysical interpretation
workstations. Exploration activities over the last three years have been rapidly
expanding. The Partnership has increased its gross undeveloped acreage from
47,973 acres at December 31, 1993 to approximately 259,000 acres at September
30, 1997, and its 3-D seismic data from 0 to 350 square miles. Substantially all
of the undeveloped acreage is the subject of active exploration efforts.
Additional undeveloped acreage is regularly added as existing exploration plays
are expanded and new plays are pursued.

The Partnership continually evaluates acquisition opportunities and may
increase its total annual capital expenditures depending upon its success in
identifying and completing attractive acquisitions. Management believes that its
expertise in legal and financial matters gives it a competitive advantage over
other independents in undertaking and completing complex acquisitions.

Reserves added from exploration, development and acquisitions over the
three years ended 1996, including revisions, total 73,700 Mcfe, which represents
130% of production for the same period. The Partnership spent $44.9 million on
these capital projects which represents a finding cost of $.60 per Mcfe, which
compares to an industry-wide weighted average domestic reserve replacement cost
from all sources for independent oil and gas companies for the same period of
$.82 Mcfe as reported by Arthur Andersen in its eighteenth annual survey of oil
and gas exploration and production companies: Oil and Gas Reserve Disclosures
(1997). In 1997, the Partnership expects to incur approximately $15.5 million of
expenditures on 115 drilling and recompletion projects. As of September 30,
1997, 63 projects had been performed, of which 39 were successful.

<PAGE> 43

Over the last three years the Partnership has undertaken approximately
400 development and exploration wells, recompletions and workover projects and
completed numerous acquisitions. As a result of these activities, including
revisions, the Partnership has replaced 145%, 132% and 116% of its production,
at an average cost of $.50, $.71, and $.64 per Mcfe for 1996, 1995, and 1994,
respectively. From January 1, 1996 through September 30, 1997, the Partnership
had a 60% success rate on its drilling, workovers and recompletions. For
purposes of this determination the Partnership has classified a well as
successful if production casing has been run for a completion attempt on the
well.

The Partnership's future growth will be driven by a combination of
development of existing projects, exploration for new reserves and select
acquisitions. The proceeds of the Offering will be utilized by the Partnership
in 1998 to accelerate the drilling of a portion of its current project inventory
which includes an estimated 67 development well and workover locations, 54 wells
and workovers that may be undertaken depending on the results of future
evaluations and 50 exploration locations, which, if successful, could lead to
additional opportunities.

BUSINESS STRATEGY

The Partnership's exploration team includes seven geoscientists and
technicians who have developed in-depth knowledge and expertise in each of the
Partnership's core operating areas and related exploration projects areas. Joint
venture and contract technical personnel and consultants who have demonstrated
experience and expertise in select areas of interest to the Partnership provide
supplemental support as needed. The technical staff uses in-house 3-D seismic
and software as well as other modern techniques in its exploration effort.

<PAGE> 44

a comprehensive interdisciplinary approach encompassing technical, financial,
legal and strategic considerations in evaluating potential acquisitions of oil
and gas properties. The Partnership's average reserve acquisition cost was $.76
per Mcfe for the three years ended December 31, 1996.

UTILIZE STRENGTHS OF PERSONNEL. The Partnership utilizes qualified and
experienced lease operators, field supervisors, engineers, landmen, accountants
and other personnel assigned to specific core areas of operation. Substantially
all of the staff have over 10 years experience in their fields, and most have
been employed by the Partnership's subsidiary, HPI, for more than 10 years. All
personnel have access to and use modern information systems, operating
technologies and equipment to help maximize production and reliability of the
Partnership's operations while minimizing costs.

ORGANIZATION

The general partner (the "General Partner") of the Partnership is
HEPGP, a Colorado limited partnership. The general partner of HEPGP is Hallwood
G.P., a Delaware corporation, which is a wholly owned subsidiary of Hallwood
Group. For purposes of this Prospectus, unless otherwise indicated, references
to the General Partner include Hallwood G.P.

The Partnership's activities are conducted through the two Operating
Partnerships. HEP is the sole limited partner and HEPGP is the sole general
partner of each of the Operating Partnerships. Solely for purposes of simplicity
in this Prospectus, unless otherwise indicated, all references to the
Partnership in connection with the ownership, exploration, development or
production of oil and gas properties include the Operating Partnerships.

The majority of the Partnership's oil and gas properties are managed
and operated by HPI, a subsidiary of the Partnership. Since neither the
Partnership nor the General Partner has any employees, HPI performs all
operations on behalf of the Partnership. In its capacity as manager and
operator, HPI pays all costs and expenses of operations and distributes all net
revenues associated with the Partnership's properties. The Partnership
reimburses HPI for its actual cost for direct and indirect expenses incurred by
HPI for the benefit of the Partnership and its properties. The indirect expenses
for which HPI is reimbursed include employee compensation, office rent, office
supplies and employee benefits. HPI does not receive any fees for its services.

HPI generally allocates its expenses among the Partnership and its
affiliates by multiplying the aggregate amount of the indirect expenses incurred
by HPI by the estimated time that the employees of HPI spend on managing the
Partnership and dividing by the aggregate time that the employees of HPI spend
on all the entities that HPI manages. Certain components of employee
compensation payable by the Partnership take into account the Partnership's
performance and its ownership interest in certain wells.

The Partnership owns 46% of the common stock of its affiliate HCRC, a
publicly traded Delaware corporation. HCRC owns 19% of the publicly traded Units
of the Partnership. HPI also performs all operations on behalf of HCRC.

<PAGE> 45

RESERVES AND PRODUCTION BY SIGNIFICANT REGIONS AND FIELDS

The following table presents the December 31, 1996 proved reserve data
and the standardized measure of discounted net future cash flows of the
Partnership by significant regions.

<TABLE>
<CAPTION>
PROVED RESERVE QUANTITIES STANDARDIZED MEASURE OF
------------------------- DISCOUNTED FUTURE NET CASH FLOWS
--------------------------------
PROVED PROVED
NATURAL GAS Bbls OF OIL UNDEVELOPED DEVELOPED TOTAL
-------- -------- -------- -------- --------
(Mmcf) (Mbbls) (Dollars in thousands)

<S> <C> <C> <C> <C> <C>
Greater Permian Region 26,477 5,395 $ 3,871 $ 63,948 $ 67,819
Gulf Coast Region 28,407 728 1,929 81,378 83,307
Rocky Mountain Region 30,811 760 500 46,992 47,492
Other 2,847 648 353 7,029 7,382
-------- -------- -------- -------- --------
88,542 7,531 $ 6,653 $199,347 $206,000
======== ======== ======== ======== ========
</TABLE>

The following table presents the oil and gas production for significant
regions for the periods indicated.

<TABLE>
<CAPTION>
PRODUCTION FOR THE PRODUCTION FOR THE
YEAR ENDED DECEMBER 31, 1996 YEAR ENDED DECEMBER 31, 1995
------------------------------ -----------------------------

NATURAL GAS Bbls OF NATURAL GAS Bbls OF
----------- ------- ----------- -------
(Mmcf) OIL (Mmcf) OIL
--- ---
(Mbbls) (Mbbls)

<S> <C> <C> <C> <C>
Greater Permian Region 2,792 512 2,907 511
Gulf Coast Region 6,015 239 6,109 244
Rocky Mountain Region 3,394 137 3,204 146
Other 585 84 815 92
------ ------ ------ ------
12,786 972 13,035 993
====== ====== ====== ======
</TABLE>

The following table presents the Partnership's extensions, reserves
added through discoveries, revisions and acquisitions and discoveries by
significant regions.

<TABLE>
<CAPTION>
FOR THE YEAR ENDED FOR THE YEAR ENDED
DECEMBER 31, 1996 DECEMBER 31, 1995
----------------- -----------------
NATURAL GAS Bbls OF OIL NATURAL GAS Bbls OF OIL
----------- ----------- ----------- -----------
(Mmcf) (Mbbls) (Mmcf) (Mbbls)

<S> <C> <C> <C> <C>
Greater Permian Region 704 422 3,992 1,494
Gulf Coast Region 176 15 582 28
Rocky Mountain Region 670 28 1,404 361
Other 133 19 19 19
----- ----- ----- -----
1,683 484 5,997 1,902
===== ===== ===== =====
</TABLE>

<PAGE> 46

A description of the Partnership's properties by region follows:

Greater Permian Region

The Partnership has significant interests in the following groups of
properties located in the Greater Permian Region in Texas and Southeast New
Mexico.

CARLSBAD/CATCLAW AREA. The Partnership's interests in the
Carlsbad/Catclaw Area as of December 31, 1996 consisted of 60 producing wells
that produce primarily natural gas and are located on the northwestern edge of
the Delaware Basin in Lea, Eddy and Chaves Counties, New Mexico. HPI operates 38
of these wells. The wells produce at depths ranging from approximately 2,500
feet to 14,000 feet from the Delaware, Atoka, Bone Springs and Morrow
formations. The Partnership has been active in this area since 1990 and
participated in the drilling or recompletion of 66 wells, 52 of which were
successful through December 31, 1996. The Partnership's working interest
averages 39% in this area. The Partnership's standardized measure of discounted
future net cash flows from this area at December 31, 1996 was approximately
$17.0 million.

The Partnership spent $900,000 in 1997 drilling two unsuccessful
exploration wells in the Delaware formation at depths of 4,500 feet and
successfully recompleting two wells. Future plans include 7 additional projects.

CROSS ROADS/OASIS AREA. The Partnership's interest in the Cross
Roads/Oasis Area consists of 32 square miles of proprietary 3-D seismic data in
Montague County, Texas. HPI is the operator, and the Partnership has an average
12.5% working interest in this area. The Partnership's primary focus in this
area is the Atoka Bend Conglomerate formations at depths of approximately 6,000
to 7,000 feet. The Partnership has future plans to drill three exploration
wells. Additional projects may be pursued if the exploration wells are
successful.

EAST KEYSTONE AREA. The Partnership's interest in East Keystone Area as
of December 31, 1996 consisted of 48 producing wells, 33 of which are operated
by HPI, in Winkler County, Texas. The primary focus of this area is the
development of the Holt and San Andreas formations at a depth of 5,100 feet. The
Partnership became active in this area in 1993 and has participated in the
drilling or recompletion of approximately 50 wells, 40 successfully, through
1996. The Partnership owns an average 35% working interest in this area. The
Partnership's standarized measure of discounted future cash flows from this area
at December 31, 1996 was approximately $11.9 million.

Through November 30, 1997, the Partnership had 13 development projects,
10 of which were successful, at an approximate cost to the Partnership of
$370,000. The Partnership's future development plans include a total of five
projects for the East Keystone area.

GARDEN CITY AREA. In 1996, the Partnership became active in the Garden
City Area in Glasscock County, Texas. This project included the acquisition and
processing of 66 square miles of nonproprietary 3-D seismic data and the
drilling of one successful exploratory well prior to the end of 1996. The
standardized measure of discounted future net cash flows from this area at
December 31, 1996 was approximately $400,000. In 1997 HEP drilled a second
successful 10,000 foot delineation well and unsuccessfully reentered an
abandoned well for total costs to the Partnership of approximately $330,000. The
Partnership has future plans for two projects in this area.

GRIFFIN AREA. In 1997, the Partnership purchased an interest in
proprietary 3-D seismic data and selected acreage within an 85 square mile area
in Texas for approximately $460,000. The Partnership has developed a number of
prospects in this project area which it plans to pursue. Through November 30,
1997 the Partnership has drilled two exploratory wells, for approximately
$415,000, one of which was successful. Future plans include a total of nine
projects with additional potential projects contingent upon the success of the
planned projects.

MERKLE AREA. The Partnership's nonoperated interest in the Merkle Area
includes 10 square miles of proprietary seismic data in Jones, Nolan and Taylor
Counties, Texas which was acquired in 1995. The seismic data has led to the
drilling of eight wells through December 31, 1996, seven of which were
successful. The Partnership's focus in this area is exploration of the Canyon,
Strawn and Ellenberger formations at depths of 3,500 to 6,500 feet. The
Partnership owns a 12.5% working interest in this area that is operated by a
third party. The standardized measure of discounted future net cash flows from
this area at December 31, 1996 was approximately $.9 million. Through

<PAGE> 47

November 30, 1997, the Partnership participated in the drilling of three
development and four exploration wells at an approximate cost to the Partnership
of $175,000. Five of the wells were successful.

Based on its success in the nonoperated Merkle Area, the Partnership
acquired 74 additional miles of proprietary 3-D seismic data adjacent to the
nonoperated area. The Partnership has drilled five successful and five
unsuccessful exploration wells through November 30, 1997 at a cost to the
Partnership of approximately $600,000. The Partnership owns an average 25%
working interest in these wells, all of which HPI operates.

The Partnership's future plans for the entire Merkle Area include
drilling 25 exploration wells with additional exploratory locations possible,
contingent upon continued exploration success.

SPRABERRY AREA. The Partnership's interests in the Spraberry Area as of
December 31, 1996 consisted of 363 producing wells, nine salt water disposal
wells and 24 shut-in wells in Dawson, Upton, Reagan and Irion Counties, Texas.
HPI operates 387 of these wells. Most of the current production from the wells
is from the Upper and Lower Spraberry, Clearfork Canyon, Dean and Fusselman
formations at depths ranging from 5,000 feet to 9,000 feet. From 1989 through
1996 the Partnership has drilled or recompleted approximately 130 wells, 114
successfully. The Partnership owns an average 45% working interest in this area.
The Partnership's standardized measure of discounted future net cash flows from
this area at December 31, 1996 was approximately $39.2 million.

Through November 30, 1997, the Partnership incurred approximately
$1,000,000 for drilling two unsuccessful exploration wells and nine development
wells, eight of which were successful. In July, the Partnership acquired
additional interests in 34 of its existing wells at a cost of approximately
$500,000.

The Partnership's future plans for the Spraberry Area include 25
development wells and workovers and additional projects contingent upon future
evaluation.

Gulf Coast Region

The Partnership has significant interests in the Gulf Coast Region in
Louisiana and South and East Texas. The Partnership's most significant interest
in the Gulf Coast Region at December 31, 1996 consisted of 10 producing natural
gas wells, one shut-in natural gas well and six salt water disposal wells
located in Lafayette Parish, Louisiana. The wells produce principally from the
Bol Mex formations at 13,500 to 14,500 feet and are operated by HPI. From 1989
through 1996 the Partnership drilled or recompleted 15 wells in this area,
eleven of which were successful. The two most significant wells in the area are
the A.L. Boudreaux #1 and the G.S. Boudreaux Estate #1, which currently
provides approximately 19% of the Partnership's total production. The
Partnership owns an average 22% working interest in the area. The Partnership's
standardized measure of discounted future net cash flows from this area at
December 31, 1996 was approximately $66.7 million.

Through November 30, 1997, the Partnership incurred approximately $2.9
million of costs in this area. The expenditures consisted of drilling five
successful development wells, three exploration wells, none of which were
successful, tubing repairs, additional perforations, workovers and acreage
acquisitions.

BISON AREA. This project is a structural gas play for the Marg Tex and
Bol Mex Formations at approximate depths of 9,000 and 13,000 feet. This is a 3-D
defined structure which is very large and is centered under an existing HPI well
in the Gulf Coast Region. The Partnership has a 2.5% working interest in this
project, which is nonoperated.

BOCA CHICA AREA. The Partnership plans to participate in a 10,000 foot
Bigneneria Humblei Formation gas well test defined by 2-D proprietary seismic
data. This well will be drilled directionally from the shore to a bottom hole
location one mile under the waters of the Gulf of Mexico. The Partnership has a
12.5% working interest in this project.

Rocky Mountain Region

The Partnership has significant interests in the following groups of
properties located in Colorado, Montana, North Dakota, Northwest New Mexico and
Wyoming.

<PAGE> 48

BEAR GULCH AREA. The Partnership plans to drill a test well in 1998 in
the Bear Gulch Area in Campbell County, Wyoming. The project will be operated by
HPI and the Partnership has a 21% interest in it. If the test well is
successful, additional development wells could be drilled.

DOUGLAS ARCH AREA. The Partnership's interest in this area at December
31, 1996 consisted of 47 producing wells in Garfield County, Colorado and Summit
County, Utah, 39 of which are operated by HPI. Ten wells produce from the Dakota
formation at depths of approximately 4,000 to 6,000 feet. From 1993 through
1996, the Partnership participated in 10 projects in this area, five of which
were successful. The Partnership's working interest in the area averages 12%.
The Partnership's standardized measure of discounted future net cash flows from
this area at December 31, 1996 was approximately $5.0 million. The Partnership
plans sixteen projects in this area with additional locations contingent upon
the success of these planned projects.

HUDSON RANCH AREA. The Hudson Ranch Area is in Golden Valley County,
North Dakota. The Partnership will participate in a 30 square mile proprietary
3-D seismic acquisition program in early 1998. The Partnership's primary
focus in this area is the development of the Mission Canyon, Lodgepole, Nisku
and Interlake formations at depths ranging from 9,000 feet to 12,000 feet. The
Partnership has incurred $325,000 through November 30, 1997 for seismic and
leasehold costs. Successful results of the seismic program could lead to the
drilling of up to eight exploratory wells, which if successful could lead to
potential future locations.

SAN JUAN BASIN. The Partnership's interest in the San Juan Basin as of
December 31, 1996 consisted of 92 producing natural gas wells located in San
Juan County, New Mexico and La Plata County, Colorado. HPI operates 54 wells in
New Mexico, 34 of which produce from the Fruitland Coal formation at
approximately 2,200 feet and 20 of which produce from the Pictured Cliffs, Mesa
Verde and Dakota formations at 1,200 to 7,000 feet. The Partnership has been
active in the New Mexico portion of the basin since 1990, and has drilled or
recompleted 40 wells, 35 of which were successful, through December 31, 1996.

In 1996, the Partnership participated in the acquisition of interests
in 38 producing natural gas wells in La Plata County, Colorado and Rio Arriba
County, New Mexico from a subsidiary of Public Service Company of Colorado.
Thirty-four of the wells were assigned to a special purpose entity owned by a
large east coast financial institution. The wells produce from the Fruitland
Coal formation at approximately 3,200 feet. In connection with the acquisition,
the Partnership monetized the Section 29 tax credits generated by the wells. The
project was financed through a third party lender using a production payment
structure. In 1996, the Partnership recompleted 10 of the wells, seven
successfully. Through November 30, 1997 four successful recompletions have been
performed. The Partnership's standardized measure of discounted future net
cash flows from this area at December 31, 1996 was approximately $14.2 million.

Future plans for the San Juan Basin include a total of 12 projects.
If field rules were changed in the future to allow downspacing, the
Partnership would have additional potential well locations.

TOOLE COUNTY AREA. The Partnership's interest in the Toole County Area
as of December 31, 1996 consisted of 85 wells, 43 of which are operated by HPI,
in Toole County, Montana. The oil wells produce from the Nisku formation at
depths of approximately 3,000 feet and the natural gas wells produce from the
Bow Island formation at depths of 900 to 1,200 feet. The Partnership became
active in this area in 1993 when it acquired these properties. From 1993 through
1996, the Partnership drilled a total of six wells, four of which were
successful. The Partnership's working interest in the area average 26%. The
Partnership's standardized measure of discounted future net cash flows from this
area at December 31, 1996 was approximately $2.6 million. Through November 30,
1997 the Partnership successfully reentered and horizontally sidetracked one
well at an approximate cost to the Partnership of $150,000. The Partnership has
future plans for 22 development wells and workovers in this area.

WEST SIOUX PASS AREA. The Partnership has participated in a project
involving a deep Red River prospect, defined by existing non-proprietary 3-D
seismic data from another Montana project the Partnership participated in. The
Partnership will have an 11% interest in this project and plans to drill one
exploratory well in the future. If successful, additional wells could be
drilled.

<PAGE> 49

Other

KANSAS AREA

The Partnership's interest in the Kansas Area as of December
31, 1996 consisted of 223 producing wells, of which 213 are operated by HPI and
10 are operated by unaffiliated entities. The wells are located in 15 counties
primarily in the Central Kansas Uplift and produce principally from the Arbuckle
and numerous Lansing-Kansas City formation zones from 3,000 feet to 6,500 feet.
The Partnership owns an average 25% working interest in the area. The
Partnership's standardized measure of discounted future net cash flows from this
area at December 31, 1996 was approximately $4.2 million. The Partnership has
15 projects planned for this area in the future.

SACRAMENTO AREA. The Partnership has an interest in proprietary 3-D
seismic data in Yolo County, California targeting the 5,000 to 8,000 foot deep
sands in the Sacramento Valley Province of Northern California. The Partnership
has a 7.5% nonoperated working interest in the project. In 1997, three
successful wells were drilled. Future plans include five exploration wells with
the potential of additional wells if successful.

STEALTH AREA. The Partnership entered into a project with Texaco to
explore for deep Springer, Hutton and Viola Formations at maximum depths of
approximately 19,000 feet in the Ardmore Basin in Carter County, Oklahoma. The
Partnership has a 5% working interest in this project. One well was drilled in
1997 at an approximate cost to the Partnership of $450,000. The well is
currently being tested. Positive test results could lead to additional locations
in the future.

OIL AND GAS RESERVES

The following reserve quantity and future net cash flow information for
the Partnership represents proved reserves that are located in the United
States. The reserves have been estimated by HPI's in-house engineers.
Approximately 80% in value of these reserves have been reviewed by Williamson
Petroleum Consultants, Inc., independent petroleum engineers. The determination
of oil and gas reserves is based on estimates that are highly complex and
interpretive. The estimates are subject to continuing change as additional
information becomes available.

The standardized measure of discounted future net cash flows is
calculated with no consideration given to future income taxes because the
Partnership is not a taxpaying entity. Under the guidelines set forth by the
SEC, the calculation is performed using year end prices held constant (unless a
contract provides otherwise) and is based on a 10% discount rate. At December
31, 1996, oil and gas prices averaged $24.18 per Bbl of oil and $3.76 per Mcf of
gas for the Partnership. The prices of oil and gas at December 31, 1996 were
substantially higher than the prices used in the previous years to estimate net
proved reserves and future net revenues and substantially higher than oil and
gas prices at September 30, 1997. Future production costs are based on year end
costs and include severance taxes. The reserve calculations using these December
31, 1996 prices result in 7.5 million Bbls of oil, 88.5 Bcf of natural gas and a
standardized measure of discounted future net cash flows of $206 million. At
December 31, 1996, the portion of the reserves attributable to the General
Partner's interest totaled 300,000 Bbls of oil and 6 Bcf of natural gas with a
standardized measure of discounted future net cash flows of $16 million, which
amounts are included in the Partnership's reserves shown in the table below.
This standardized measure of discounted future net cash flows is not necessarily
representative of the market value of the Partnership's properties. See "Risk
Factors--Risks Inherent in the Partnership's Business--Volatility of Oil and Gas
Prices."

<PAGE> 50

and workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery, and estimates of the
future net cash flows expected therefrom prepared by different engineers, or by
the same engineers but at different times, may vary substantially and such
reserve estimates may be subject to downward or upward adjustment based upon
such factors. Actual production, revenues and expenditures with respect to the
Partnership's reserves will likely vary from estimates, and such variances may
be material.

The following table summarizes the Partnership's proved reserves, the
estimated future net revenues from such proved reserves and the standardized
measure of discounted future net cash flows attributable thereto at December 31,
1996, 1995 and 1994:

<TABLE>
<CAPTION>
AT DECEMBER 31,(1)
--------------------------------------------
1996 1995 1994
-------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT FOR
WEIGHTED AVERAGE SALES PRICES)
<S> <C> <C> <C>
Proved reserves:
Oil (Mbbl)........................................ 7,531 8,098 6,738
Natural gas (Mmcf)................................ 88,542 83,112 85,585
Total (Mmcfe) ................................ 133,728 131,700 126,013
Estimated future net cash flows(2)................ $334,000 $187,000 $153,000
Standardized measure of discounted future
net cash flows(3)......................... $206,000 $124,000 $104,000
Proved developed reserves:
Oil (Mbbl)........................................ 7,056 7,444 6,166
Natural gas (Mmcf)................................ 85,848 77,378 79,699
Total (Mmcfe) ................................ 128,184 122,042 116,695
Estimated future net cash flows(3)................ $323,000 $178,000 $138,000
Standardized measure of discounted future
net cash flows(3).............................. $199,000 $118,000 $ 94,000
Weighted average sales prices(2):
Oil (per Bbl)..................................... $ 24.18 $ 17.95 $ 15.80
Natural gas (per Mcf)............................. $ 3.76 $ 2.03 $ 1.72
</TABLE>

(1) Excludes pro rata proved reserves attributable to the Partnership's 46%
equity interest in HCRC. See "Business and Properties--Investment in
Hallwood Consolidated Resources Corporation."
(2) Includes the effects of hedging.
(3) The standardized measure of discounted future net cash flows prepared by
the Partnership represents the present value (using an annual discount
rate of 10%) of estimated future net revenues from the production of
proved reserves. No effect is given to income taxes as the Partnership is
not a taxpayer. See the Supplemental Oil and Gas Reserve Information
attached to the December 31, 1996 Consolidated Financial Statements of
the Partnership included elsewhere in this Prospectus for additional
information regarding the disclosure of the standardized measure
information in accordance with the provisions of Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."

<PAGE> 51

VOLUMES, SALES PRICES AND OIL AND GAS PRODUCTION EXPENSE

The following table sets forth certain information regarding the
production volumes and weighted average sales prices received for and average
production costs associated with the Partnership's sale of oil and gas for the
periods indicated.

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, (1)
------------------------------------
1996 1995 1994
------------- ------------- -------------
<S> <C> <C> <C>
Production:
Oil (Mbbl) 972 993 939
Natural gas (Mmcf) 12,786 13,035 13,208
Total (Mmcfe) 18,618 18,993 18,842
Weighted average sales price(2):
Oil (per Bbl) $ 20.10 $ 17.36 $ 16.47
Natural gas (per Mcf) $ 2.24 $ 1.82 $ 1.97
Production operating expense
(per Mcfe)(3) $ 0.62 $ 0.60 $ 0.65
</TABLE>

- ----------

(1) Excludes pro rata production attributable to the Partnership's 46%
equity interest to HCRC. See "Business and Properties--Investment in
Hallwood Consolidated Resources Corporation."
(2) Includes the effects of hedging.
(3) Includes production taxes.

DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES

The following table sets forth certain information regarding the costs
incurred by the Partnership and its consolidated subsidiaries in the purchase of
proved and unproved properties and in its development and exploration
activities.

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, (1)
------------------------------------
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Acquisition costs:
Proved properties $ 2,321 $ 2,727 $ 3,724
Unproved prospects 560 793 183
Development costs 9,587 11,880 4,995
Exploration costs 831 2,368 4,983
------- ------- -------
Total costs incurred $13,299 $17,768 $13,885
======= ======= =======
</TABLE>

- ---------------

(1) Excludes pro rata costs attributable to the Partnership's 46% equity
interest to HCRC. See "Business and Properties--Investment in Hallwood
Consolidated Resources Corporation."

<PAGE> 52

PRODUCTIVE OIL AND GAS WELLS

The following table summarizes the productive oil and gas wells as of
December 31, 1996 attributable to the Partnership's direct interests.

<TABLE>
<CAPTION>
GROSS NET
----- ---
<S> <C> <C>
Productive Wells
Oil 736 273
Natural gas 369 127
----- ---
Total 1,105 400
===== ===
</TABLE>

OIL AND GAS ACREAGE

The following table sets forth the developed and undeveloped leasehold
acreage held directly by the Partnership as of December 31, 1996. Developed
acres are acres that are spaced or assignable to productive wells. Undeveloped
acres are acres on which wells have not been drilled or completed to a point
that would permit the production of commercial quantities of oil or gas,
regardless of whether or not such acreage contains proved reserves. Gross acres
are the total number of acres in which the Partnership has a working interest.
Net acres are the sum of the Partnership's fractional interests owned in the
gross acres.

<TABLE>
<CAPTION>
GROSS NET
------- -------

<S> <C> <C>
Developed acreage 176,795 79,311
Undeveloped acreage 130,618 50,103
------- -------
Total 307,413 129,414
======= =======
</TABLE>

States in which the Partnership holds undeveloped acreage include Texas,
Louisiana, Montana, Wyoming, New Mexico, Kansas, Colorado, North Dakota and
Michigan.

DRILLING ACTIVITY

The following table sets forth the number of wells attributable to the
Partnership's direct interest drilled in the most recent three years.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
1996 1995 1994
-------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----

<S> <C> <C> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Productive 29 6.6 66 28.0 30 14.6
Dry 4 .9 2 .5 4 .7
----- ----- ----- ----- ----- -----
Total 33 7.5 68 28.5 34 15.3
===== ===== ===== ===== ===== =====

EXPLORATORY WELLS:
Productive 2 .2 5 .6 2 .1
Dry 4 .6 1 .9 6 1.2
----- ----- ----- ----- ----- -----
Total 6 .8 6 1.5 8 1.3
===== ===== ===== ===== ===== =====
</TABLE>

MARKETING

The oil and gas produced from the Partnership's properties has
typically been marketed through normal channels for such products. The
Partnership generally sells its oil at local field prices generally paid by the
principal purchasers of crude oil. The majority of the Partnership's natural gas
production is sold on the spot market, and is transported in intrastate and
interstate pipelines.

<PAGE> 53

Both oil and gas are purchased by refineries, major oil companies,
public utilities, industrial customers and other users and processors of
petroleum products. The Partnership is not confined to, nor dependent upon, any
one purchaser or small group of purchasers. Accordingly, the loss of a single
purchaser, or a few purchasers, would not materially affect the Partnership's
business because there are numerous purchasers in the areas in which the
Partnership sells its production. For the years ended December 31, 1996, 1995
and 1994, however, purchases by the following companies exceeded 10% of the
total oil and gas revenues of the Partnership:

<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Conoco Inc. 28% 30% 23%
Marathon Petroleum Company 11% 14% 12%
</TABLE>

Factors, if they were to occur, which might adversely affect the Partnership
include decreases in oil and gas prices, the reduced availability of a market
for production, rising operational costs of producing oil and gas, compliance
with, and changes in, environmental control statutes and increasing costs of
transportation.

INVESTMENT IN HALLWOOD CONSOLIDATED RESOURCES CORPORATION

The preceding information concerning the Partnership's oil and gas
reserves, production and costs does not include any data relating to HCRC, of
which the Partnership owns 46% of the common stock as of December 10, 1997. The
Partnership accounts for its interest in HCRC using the equity method of
accounting. The following information is intended to reflect the Partnership's
proportionate share of HCRC's operations. The Partnership does not have any
rights to any of HCRC's assets or any obligations to pay any of HCRC's
liabilities, and the information shown is for illustrative purposes only. At
December 10, 1997, the common stock of HCRC held by the Partnership had a market
value of $33.3 million, based on the closing sales price of the common stock on
the Nasdaq Stock Market on that date.

The following table sets forth summary data with respect to the
historical production, estimated historical proved oil and gas reserves and
estimated future net cash flows attributable to the Partnership's 46% interest
in the common stock of HCRC.

<TABLE>
<CAPTION>
AS OF AND FOR THE PERIODS ENDED
DECEMBER 31,
------------------------------------
1996 1995 1994
---------- ----------- -----------
(DOLLARS IN THOUSANDS)

<S> <C> <C> <C>
Production:
Oil (Mbbls).................................................. 307 281 223
Natural gas (Mmcf)........................................... 2,822 2,634 2,237
Total (Mmcfe)................................................ 4,664 4,320 3,575
Net proved reserves (end of period):
Oil (Mbbls).................................................. 2,680 2,482 1,771
Natural gas (Mmcf)........................................... 22,786 15,782 14,548
Total (Mmcfe)................................................ 38,866 30,674 25,174
Net proved developed reserves (end of period):
Oil (Mbbls).................................................. 2,375 2,433 1,346
Natural gas (Mmcf)........................................... 22,160 14,507 13,433
Total (Mmcfe)................................................ 36,410 29,105 21,509
Estimated future net revenues before income taxes........................ $ 90,248 $ 41,131 $ 26,136
Present value of estimated future net revenues before income taxes....... $ 79,689 $ 39,735 $ 16,466
Standardized measure of discounted future net cash flows................. $ 47,701 $ 25,532 $ 16,466
</TABLE>

<PAGE> 54

The following table sets forth summary data with respect to HCRC's
results of operations for oil and gas activities attributable to the
Partnership's 46% interest in the common stock of HCRC.

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas revenue $ 11,690 $ 7,825 $ 6,522
Production operating expense (3,790) (2,894) (3,008)
Depreciation, depletion, amortization and property
impairment expense (3,257) (2,792) (3,695)
Income tax benefit (expense) 23 (813) 73
-------- -------- --------
Net income (loss) from oil and gas activities $ 4,666 $ 1,326 $ (108)
======== ======== ========
</TABLE>

COMPETITION

The Partnership encounters competition from other oil and gas companies
in all areas of its operations, including the acquisition of exploratory
prospects and proven properties. The Partnership's competitors include major
integrated oil and gas companies and numerous independent oil and gas companies,
individuals and drilling and income programs. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Partnership's and, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Partnership. These companies may be able to pay more for exploratory prospects
and productive oil and gas properties and may be able to define, evaluate, bid
for and purchase a greater number of properties and prospects than the
Partnership's financial or human resources permit. The Partnership's ability to
explore for oil and gas prospects and to acquire additional properties in the
future will be dependent upon its ability to conduct its operations, to evaluate
and select suitable properties and to consummate transactions in a highly
competitive environment. See "Risk Factors--Risks Inherent in the
Partnership's Business--Competition."

REGULATION

The availability of a ready market for oil and gas production depends
upon numerous factors beyond the Partnership's control. These factors include
regulation of oil and gas production, federal and state regulations governing
environmental quality and pollution control, state limits on allowable rates of
production by well or proration unit, the amount of oil and gas available for
sale, the availability of adequate pipeline and other transportation and
processing facilities, and the marketing of competitive fuels. For example, a
productive natural gas well may be "shut-in" because of an oversupply of natural
gas or lack of an available natural gas pipeline in the areas in which the
Partnership may conduct operations. State and federal regulations generally are
intended to prevent waste of oil and gas, protect rights to produce oil and gas
between owners in a common reservoir, control the amount of oil and gas produced
by assigning allowable rates of production, and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies. The following discussion summarizes the regulation of the
United States oil and gas industry. The Partnership believes that it is in
substantial compliance with these statutes, rules, regulations and governmental
orders, although there can be no assurance that this is or will remain the case.
The following discussion is not intended to constitute a complete discussion of
the various statutes, rules, regulations and governmental orders to which the
Partnership's operations may be subject.

Regulation of Oil and Gas Exploration and Production

The Partnership's operations are subject to various types of regulation
at the federal, state and local levels. Such regulation includes requiring
permits for the drilling of wells, maintaining bonding requirements in order to
drill or operate wells, and regulating the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the plugging and abandoning of wells and the disposal
of fluids used in connection with operations. The Partnership's operations are
also subject to various conservation laws and regulations.

<PAGE> 55

These include the regulation of the size of drilling and spacing units or
proration units, the density of wells that may be drilled, and the unitization
or pooling of oil and gas properties. In this regard, some states allow the
forced pooling or integration of tracts to facilitate exploration while other
states rely primarily or exclusively on voluntary pooling of lands and leases.
In areas where pooling is voluntary, it may be more difficult to form units, and
therefore more difficult to develop a project, if the operator owns less than
100% of the leasehold. In addition, state conservation laws establish maximum
rates of production from oil and natural gas wells, generally prohibit the
venting or flaring of natural gas, and impose certain requirements regarding the
ratability of production. The effect of these regulations may limit the amount
of oil and natural gas the Partnership can produce from its wells and may limit
the number of wells or the locations at which the Partnership can drill. The
regulatory burden on the oil and gas industry increases the Partnership's costs
of doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are periodically expanded, amended and reinterpreted, the
Partnership is unable to predict the future cost or impact of complying with
such regulations.

Federal Regulation of Sales and Transportation of Natural Gas

Prior to January 1, 1993, the sale for resale of certain categories of
natural gas production was price regulated pursuant to the Natural Gas Act of
1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations
promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). In
1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended the
NGPA to remove both price and non-price controls from natural gas sold in "first
sales" as of January 1, 1993. While sales by producers of natural gas, such as
the Partnership, can currently be made at uncontrolled market prices, Congress
could reenact price controls in the future.

The Partnership's sales of natural gas are affected by the
availability, terms and cost of transportation. The price and terms for access
to pipeline transportation remain subject to extensive federal and state
regulation. Several major regulatory changes have been implemented by Congress
and the FERC from 1985 to the present that affect the economics of natural gas
production, transportation and sales. In addition, the FERC continues to
promulgate revisions to various aspects of the rules and regulations affecting
those segments of the natural gas industry, most notably interstate natural gas
transmission companies, that remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purpose of many of these regulatory changes is to
promote competition among the various sectors of the natural gas industry and
these initiatives generally reflect more light-handed regulation of the natural
gas industry. The ultimate impact of the complex rules and regulations issued by
the FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial and
FERC final decisions.

The Partnership cannot predict what further action the FERC will take
on these matters; however, the Partnership does not believe that the effect of
FERC actions on it will be materially different than the effect on other natural
gas producers, gatherers and marketers with which the Partnership competes. The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue.

Oil Price Controls and Transportation Rates

Sales of crude oil, condensate and gas liquids by the Partnership are
not currently regulated and are made at market prices. The FERC has issued a
series of rules (Order Nos. 561 and 561-A) establishing an indexing system under
which oil pipelines will be able to change their transportation rates, subject
to prescribed ceiling levels. The indexing system, which allows or may require
pipelines to make rate changes to track changes in the Producer Price Index for
Finished Goods, minus one percent, became effective January 1, 1995. The FERC's
decision in this matter was recently affirmed by the Court. The Partnership is
not able at this time to predict the effects of Order Nos. 561 and 561-A, if
any, on the transportation costs associated with oil production from the
Partnership's oil producing operations; however, the Partnership does not
believe it will be affected by these orders materially differently than other
oil producers with which it competes.

<PAGE> 56

Environmental Regulations

The Partnership's operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years. The
trend of more expansive and stricter environmental legislation and regulations
could continue. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes environmental protection requirements
that result in increased costs to the oil and gas industry in general, the
business and prospects of the Partnership could be adversely affected.

The Partnership generates wastes, including hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The EPA and various state agencies have limited the
approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by the Partnership's oil and natural gas
operations that are currently exempt from regulation as "hazardous wastes" may
in the future be designated as "hazardous wastes" and, therefore, be subject to
more rigorous and costly operating and disposal requirements.

The Partnership currently owns or leases numerous properties that for
many years have been used for the exploration and production of oil and gas.
Although the Partnership believes that it has utilized good operating and waste
disposal practices, prior owners and operators of these properties may not have
utilized similar practices, and hydrocarbons or other wastes may have been
disposed of or released on or under the properties owned or leased by the
Partnership or on or under locations where such wastes have been taken for
disposal. In addition, many of these properties have been operated by third
parties whose treatment and disposal of hydrocarbons or other wastes was not
under the Partnership's control. These properties and the wastes disposed
thereon may be subject to CERCLA (as defined herein), RCRA and analogous state
laws. Under such laws, the Partnership could be required to remove or remedy
previously disposed wastes (including wastes disposed of or released by prior
owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.

The Partnership's operations may be subject to the Federal Clean Air
Act ("CAA") and comparable state and local requirements. Amendments to the CAA
were adopted in 1990 and contain provisions that may result in the gradual
imposition of certain pollution control requirements with respect to air
emissions from the operations of the Partnership. The EPA and states have been
developing regulations to implement these requirements. The Partnership may be
required to incur certain capital expenditures in the next several years for air
pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues.
However, the Partnership does not believe its operations will be materially
adversely affected by any such requirements.

Federal regulations require certain owners or operators of facilities
that store or otherwise handle oil, such as the Partnership, to prepare and
implement oil and hazardous substance spill prevention, control and
countermeasure plans relating to the possible discharge of oil into surface
waters. The Oil Pollution Act of 1990, as amended ("OPA"), contains numerous
requirements relating to the prevention of and response to oil spills into
waters of the United States. The OPA subjects owners of facilities to strict
joint and several liability for all containment and cleanup costs and certain
other damages arising from a spill, including, but not limited to, the costs of
responding to a release of oil to waters of the United States. The OPA also
requires owners and operators of offshore facilities that could be the source of
an oil spill into waters of the United States, including wetlands, to post a
bond, letter of credit or other form of financial assurance in an amount ranging
from $35 million to as much as $150 million, to cover costs that could be
incurred by governmental authorities in responding to an oil spill. In addition
to OPA, other federal and state laws for the control of water pollution also
provide varying civil and criminal penalties and liabilities in the case of
releases of petroleum or its derivatives into surface waters or into the ground.
Regulations are currently being developed under OPA and state laws concerning
oil pollution prevention and other matters that may impose additional regulatory
burdens on the Partnership. In addition, the Federal Clean Water Act ("CWA") and
analogous state laws require permits to be obtained to authorize discharge into
surface waters or to construct facilities in wetland areas. With respect to
certain of its operations, the Partnership is required to maintain such permits
or meet general permit requirements. The EPA also regulates discharges of storm
water runoff. This program requires covered facilities to obtain individual
permits, participate in a group permit or seek coverage under an EPA general
permit. The Partnership believes that it will be able

<PAGE> 57

to obtain, or be included under, such permits, where necessary, with minor
modifications to existing facilities and operations that would not have a
material effect on the Partnership.

The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are associated with a release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.

Management believes that the Partnership is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect on
the Partnership.

OPERATING HAZARDS AND INSURANCE

The oil and gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures and discharges of toxic gases, the occurrence of any of
which could result in substantial losses to the Partnership due to injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, cleanup responsibilities,
regulatory investigation and penalties and suspension of operations. As is
common in the oil and gas industry, the Partnership is not fully insured against
the occurrence of these events either because insurance is not available or
because the Partnership has elected not to insure against their occurrence
because of prohibitive premium costs. The occurrence of a significant event not
fully insured or indemnified against could materially and adversely affect the
Partnership's financial condition and results of operations.

TITLE TO PROPERTIES

The Partnership believes it has satisfactory title to all of its
producing properties in accordance with standards generally accepted in the oil
and gas industry. The Partnership's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens that the Partnership believes do not materially interfere with the
use of or affect the value of such properties. The Credit Facilities are secured
by 80% of all of the Partnership's oil and gas properties.

The Partnership expects to make acquisitions of oil and gas properties
from time to time. In making an acquisition, the Partnership generally focuses
most of its title and valuation efforts on the more significant properties. As
is customary in the industry in the case of undeveloped properties, little
investigation of record title is made at the time of acquisition (other than a
preliminary review of local records). Investigations, including a title opinion
of local counsel, are generally made before commencement of drilling operations.
It is generally not feasible, however, for the Partnership to review in-depth
every property it purchases and all records with respect to such properties.
However, even an in-depth review of properties and records might not necessarily
reveal existing or potential problems, nor would it permit the Partnership to
become familiar enough with the properties to assess fully their deficiencies
and capabilities. Evaluation of future recoverable reserves of oil and gas,
which is an integral part of the property selection process, is a process that
depends upon evaluation of existing geological, engineering and production data,
some or all of which may prove to be unreliable or not indicative of future
performance. See "Risk Factors--Risks Inherent in the Partnership's
Business--Uncertainty of Reserve Information and Future Net Revenue Estimates."
To the extent the seller does not operate the properties, obtaining access to
properties and records may be more difficult. Even when problems are identified,
the seller may not be willing or financially able to give contractual protection
against such problems, and the Partnership may decide to assume environmental
and other liabilities in connection with acquired properties. See "Risk
Factors--Risks Inherent in the Partnership's Business--Acquisition Risks."

<PAGE> 58

EMPLOYEES

The Partnership has no employees. At September 30, 1997, HPI had
approximately 130 employees, including five geologists/geophysicists and eight
engineers. The Partnership believes that HPI's relationships with its employees
are good. None of HPI's employees are covered by a collective bargaining
agreement. Field and on-site production operation services, such as pumping,
maintenance, dispatching, inspection and testing, are generally provided by
independent contractors.

LEGAL PROCEEDINGS

Concise Oil and Gas Partnership ("Concise"), a wholly owned subsidiary
of the Partnership, is a defendant in a lawsuit styled Dr. Allen J. Ellender,
Jr. et al. vs. Goldking Production Company, et al., filed in the Thirty-Second
Judicial District Court, Terrebonne Parish, Louisiana on May 30, 1996. The
approximately 150 plaintiffs in this proceeding are seeking unspecified damages
for alleged breaches of certain oil, gas and mineral leases in the Northeast
Montegut Field, Terrebonne Parish, Louisiana. In addition, they are asking for
an accounting from Concise for production of natural gas for the period of time
from 1983 through November 1987. Specifically, as to the claims against Concise,
the suit alleges that Concise failed to obtain the prices to which it was
allegedly entitled for natural gas sold in this field in the 1980s under a long
term natural gas sales contract. The plaintiffs, royalty and overriding royalty
owners, allege that as a result of the alleged imprudent marketing practices,
they are entitled to their share of the prices which Concise should have
obtained. Plaintiffs have also sued approximately 35 other companies and
individuals, and allege that Concise is jointly and severally liable with the
rest of the defendants for the claims raised by the plaintiffs. The claims
raised against the other defendants are similar in substance to those raised
against Concise, but seek damages and an accounting for the period of time from
1983 until the present time. While the trial of this case is currently set for
August 1998, the trial date will most likely be continued beyond that date. The
outcome of this litigation cannot be predicted with certainty. However, the
Partnership believes that the claims asserted against Concise are without merit
and intends to vigorously defend against them.

In addition to the litigation noted above, the Partnership and its
subsidiaries are from time to time subject to routine litigation and claims
incidental to their business, which the Partnership believes will be resolved
without material effect on the Partnership's financial position.

<PAGE> 59

MANAGEMENT

GENERAL

The Partnership is a limited partnership managed by its General
Partner, and neither the Partnership nor the General Partner has any officers or
directors. The General Partner is HEPGP Ltd., a Colorado limited partnership.
The general partner of HEPGP is Hallwood G.P., a Delaware corporation, which is
a wholly owned subsidiary of Hallwood Group. HEPGP became the General Partner of
the Partnership on November 26, 1996, after the former general partner of the
Partnership, Hallwood Energy Corporation ("HEC"), merged into Hallwood Group.
The principal duties and powers of the General Partner, which are performed by
employees of HPI acting on behalf of the General Partner, are arranging
financing for the Partnership, seeking out, negotiating and acquiring for the
Partnership suitable leases and other prospects, managing properties owned by
the Partnership, generally dealing for the Partnership with third parties and
attending to the general administration of the Partnership and its relations
with the limited partners.

DIRECTORS, OFFICERS AND KEY EMPLOYEES

Neither the Partnership nor the General Partner has any employees. HPI
performs duties related to the management and operation of the Partnership,
including the operation of various properties in which the Partnership owns an
interest. Following are brief biographies of the directors, officers and key
employees of Hallwood G.P. and HPI.

Anthony J. Gumbiner, 53, has served as a director and Chief Executive
Officer of Hallwood G.P. since March 1997. He was Chairman of the Board of HEC
from May 1984 until HEC's merger into Hallwood Group in November 1996. He was
Chief Executive Officer of HEC from February 1987 to November 1996. He has also
served as Chairman of the Board of Directors of Hallwood Group, a diversified
holding company with energy, real estate, textile products and hotel operations,
since 1981 and as Chief Executive Officer of Hallwood Group since April 1984.
Mr. Gumbiner has been a director and Chief Executive Officer of HCRC since
February 1992. Mr. Gumbiner has also served as Chairman of the Board of
Directors and as a director of Hallwood Holdings S.A., a Luxembourg real estate
investment company, since March 1984. He has been a director of Hallwood Realty
Corporation ("Hallwood Realty"), which is the general partner of Hallwood Realty
Partners, L.P., since November 1990. He is a Solicitor of the Supreme Court of
Judicature of England.

William L. Guzzetti, 54, has been President of Hallwood G.P. and HPI
since October 1989, and a director of Hallwood G.P. and HPI since August 1989.
He was President, Chief Operating Officer and a director of HEC from February
1985 until November 1996. Mr. Guzzetti joined HEC in February 1976 as Vice
President, Secretary and General Counsel and served in these positions until
November 1980. He served as Senior Vice President, Secretary and General Counsel
of HEC from November 1980 until February 1985, when he became President of HEC.
Mr. Guzzetti has been President, Chief Operating Officer and a director of HCRC
since May 1991. Mr. Guzzetti is also an Executive Vice President of Hallwood
Group and in that capacity may devote a portion of his time to the activities of
Hallwood Group, including the management of real estate investments,
acquisitions and restructurings of entities controlled by Hallwood Group. He is
a director and President of Hallwood Realty and in that capacity may devote a
portion of his time to the activities of Hallwood Realty.

Russell P. Meduna, 42, has served as Executive Vice President of
Hallwood G.P. and HPI since October 1989. He was Executive Vice President of HEC
from June 1991 until November 1996. He was Vice President of HEC from May 1990
until June 1991. Mr. Meduna became Executive Vice President of HCRC in June
1992. Mr. Meduna was Vice President of Hallwood G.P. and HPI from April 1989 to
October 1989 and Manager of Operations from January 1989 to April 1989. He
joined HPI in 1984 as Production Manager. Prior to joining HPI, he was employed
by both major and independent oil companies. Mr. Meduna is a registered
professional engineer in the States of Colorado and Texas.

Cathleen M. Osborn, 45, has served as Vice President, Secretary and
General Counsel of Hallwood G.P. and HPI since September 1986. She was Vice
President, Secretary and General Counsel of HEC from June 1991 until November
1996. Ms. Osborn became Secretary and General Counsel of HCRC in May 1992 and
Vice President in June 1992. She joined Hallwood G.P. and HPI in 1985 as senior
staff attorney. Ms. Osborn is a member of the Colorado Bar Association.

<PAGE> 60

Robert Pfeiffer, 41, has served as Vice President of Hallwood G.P. and
HPI since August 1986. He was Vice President of HEC from June 1991 until
November 1996. Mr. Pfeiffer became Chief Financial Officer of HPI in June 1994.
He has been Vice President of HPI since June 1992. He joined Hallwood G.P. and
HPI in 1984. From July 1979 to May 1984, he was employed by Price Waterhouse as
a senior accountant. Mr. Pfeiffer is a member of the American Institute of
Certified Public Accountants and the Colorado Society of Certified Public
Accountants.

Betty J. Dieter, 49, has been Vice President of HPI responsible for
domestic operations since January 1995. Her previous positions with HPI have
included Operations Manager, Rocky Mountain and Mid-Continent District Manager
and Manager for Operations Accounting and Administration. She joined HPI in
1985, and has 25 years experience in accounting and operations, 18 of which are
in the oil and gas industry. Ms. Dieter is a Certified Public Accountant.

George Brinkworth, 55, has been Vice President-Exploration and
International Division of HPI since August 1994. He became associated with HPI
in 1987 when he was President of a joint venture program funded by HPI and two
other domestic oil companies. Mr. Brinkworth has 33 years experience with
various exploration and production companies, including previous responsibility
for operations in the United Kingdom, Spain, Morocco, Egypt and Indonesia. He is
a registered geophysicist in the State of California.

William H. Marble, 47, has served as Vice President of HPI since
December 1990. His previous positions with HPI have included Texas/Gulf Coast
District Manager, Manager of Nonoperated Properties and Chief Engineer. He
joined a predecessor general partner of the Partnership in 1984. Mr. Marble is a
registered engineer in the State of Colorado and has 23 years oil and gas
engineering experience.

Brian M. Troup, 50, has served as a director of Hallwood G.P. since
March 1997. Mr. Troup was a director of HEC from May 1984 until November 1996.
He has been President and Chief Operating Officer of Hallwood Group since April
1986, and he is a director. He has been a director of HCRC since February 1992.
Mr. Troup is a director of Hallwood Holdings S.A. and of Hallwood Realty. He is
an associate of the Institute of Bankers in Scotland and a member of the Society
of Investment Analysts in the United Kingdom.

Hans-Peter Holinger, 55, has served as a director of Hallwood G.P.
since March 1997. He was a director of HEC from May 1984 until November 1996.
Mr. Holinger served as Managing Director of Interallianz Bank Zurich A.G. from
1977 to February 1993. Since February 1993, he has been the majority owner of
Holinger Asset Management AG, Zurich. Mr. Holinger is a citizen of Switzerland.

Rex A. Sebastian, 68, has served as a director of Hallwood G.P. since
March 1997. He was a director of HEC from January 1993 until November 1996. Mr.
Sebastian is a member of the board of directors of Ferro Corporation. He served
as Senior Vice President--Operations of Dresser Industries, Inc. from January
1975 until his retirement in July 1985. He joined Dresser in 1966. Mr. Sebastian
is now a private investor.

Nathan C. Collins, 63, has served as a director of Hallwood G.P. since
March 1997. He was a director of HEC from January 1993 until November 1996. From
March 1, 1995 to March 1, 1996, he was President, Chief Executive Officer and a
director of Flemington National Bank & Trust Co. in Flemington, New Jersey. From
November 1987 until December 1994, he was Chairman of the Board of Directors,
President and Chief Executive Officer of BancTexas Group Inc. He began his
banking career in August 1964 with the Valley National Bank in Phoenix, Arizona
and held various positions there, finally becoming Executive Vice President,
Senior Credit Officer and Manager of Asset/Liability Group of the bank. Mr.
Collins is now a private investor.

<PAGE> 61
EXECUTIVE COMPENSATION

GENERAL

Neither the Partnership nor the General Partner has any employees.
Management services are provided to the Partnership by HPI, a subsidiary of the
Partnership. Employees of HPI perform all duties related to the management of
the Partnership on behalf of the General Partner. Since HPI also performs
services for HCRC, the Partnership is charged for management services by HPI
based on an allocation procedure that takes into account the amount of time
spent on management, the number of properties owned by the Partnership and the
Partnership's performance relative to HCRC and other related entities. The
allocation procedure is applied consistently to all related entities for which
HPI performs services. In 1996 the Partnership reimbursed HPI for
approximately $1.9 million of expenses, of which $675,338 was attributable to
compensation paid to executive officers of Hallwood G.P. The reimbursement
paid in 1997 is not yet available.

COMPENSATION OF EXECUTIVE OFFICERS

The following table sets forth the compensation to the Chief Executive
Officer of Hallwood G.P. and each of the four other most highly compensated
officers of Hallwood G.P. whose compensation paid by HPI exceeded $100,000
(determined for the year ended December 31, 1996) for services to the
Partnership, its subsidiaries and its General Partner for the years ended
December 31, 1996, 1995, and 1994.

SUMMARY COMPENSATION TABLE

Long Term
Annual Compensation Compensation
------------------- ----------------------------
Securities
Name & Principal Position Underlying
------------------------- ---------- LITP All Other
Year Salary Bonus Options/SARs(#) Payouts Compensation (1)
---- ------ ----- ------------- --------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Anthony J. Gumbiner (2) . . 1996 $250,000 $ 0 0 $ 0 $ 0

Chief Executive 1995 250,000 0 (3) 0 0
Officer 1994 125,500 0 0 0 0

William L. Guzzetti . . . . 1996 204,294 131,500 0 33,170 5,699
President and Chief 1995 204,412 75,000 (3) 15,753 6,004
Operating Officer 1994 200,240 72,800 0 9,449 6,004

Russell P. Meduna . . . . . 1996 163,664 101,900 0 33,170 4,500
Executive Vice 1995 167,364 161,000 (3) 15,753 4,810
President 1994 164,204 24,200 0 9,449 4,409

Robert S. Pfeiffer . . . . 1996 107,518 56,700 0 23,092 4,300
Vice President and 1995 109,949 94,000 (3) 11,692 3,160
Chief Financial 1994 107,755 25,700 0 6,963 3,160
Officer

Cathleen M. Osborn . . . . 1996 105,685 62,400 0 23,092 4,500
Vice President and 1995 109,069 95,000 (3) 11,692 3,160
General Counsel 1994 105,848 24,600 0 6,963 3,160
</TABLE>

- ----------------------

(1) Employer contribution to 401(k) and a service award of $1,199 paid to
Mr. Guzzetti.

57
<PAGE> 62

(2) For 1994, 1995 and 1996, Mr. Gumbiner had a Compensation Agreement with
HPI. $250,000 was paid under this agreement in 1995 and 1996; $125,500
was paid in 1994. The Compensation Agreement was effective August 1,
1994 and terminated effective December 1996. In addition to
compensation listed in the table, HPI has a consulting agreement with
Hallwood Group for 1994 through 1996, pursuant to which Hallwood Group
received an annual consulting fee of $300,000 from affiliates of HPI.
The consulting services were provided by HSC Financial Corporation
("HSC Financial"), through the services of Mr. Gumbiner and Mr. Troup,
and Hallwood Group paid the annual fee it received to HSC Financial.

(3) Consists of the following options, all of which were granted in 1995.
All of the HCRC Options have been adjusted to give effect to the
3-for-1 split effective in 1997.

Name Company Options/SARs (#)
---- -------
<S> <C> <C>
Anthony J. Gumbiner . . . . . . . . . . . HEP 127,500
HCRC 47,700

William L. Guzzetti . . . . . . . . . . . HEP 63,750
HCRC 23,850
Russell P. Meduna . . . . . . . . . . . . HEP 59,500
HCRC 22,260

Robert S. Pfeiffer . . . . . . . . . . . HEP 25,500
HCRC 9,540

Cathleen M. Osborn . . . . . . . . . . . HEP 25,500
HCRC 9,540
</TABLE>

OPTION GRANTS AND EXERCISES IN LAST FISCAL YEAR

No options were granted during 1996. No executive officer exercised
options during 1996.

Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End
Option/SAR Values

<TABLE>
<CAPTION>
Number of Securities Underlying Value of Unexercised
Unexercised Options/SARs at FY- End (#) In-the-Money Options/SARs at FY-End ($)
Name Exercisable/Unexercisable (1)(3) Exercisable/Unexercisable (2)(4)
---- -------------------------------- --------------------------------

<S> <C> <C> <C>
Anthony J. Gumbiner HEP 85,425 / 42,075 266,593 / 131,484
HCRC 31,800 / 15,900 524,700 / 262,350
William L. Guzzetti HEP 42,713 / 21,038 133,477 / 65,742
HCRC 15,900 / 7,950 262,350 / 131,175

Russell P. Meduna HEP 39,975 / 19,635 124,578 / 61,359
HCRC 14,838 / 7,422 244,827 / 122,463
Robert S. Pfeiffer HEP 17,085 / 8,415 53,391 / 26,297
HCRC 6,360 / 3,180 104,940 / 52,470
Cathleen M. Osborn HEP 17,085 / 8,415 53,391 / 26,297
HCRC 6,360 / 3,180 104,940 / 52,470
</TABLE>

- ---------------------

(1) All of the HEP options expire January 31, 2005.

58
<PAGE> 63

(2) The exercise price of the HEP options is $5.75 per Class A Unit. The
closing price of the Class A Units was $8.875 on December 31, 1996.

(3) The HCRC options have a ten-year term and vest cumulatively over three
years at the rate of 1/3 on each of the date of grant and the first
two anniversaries of the grant date. All options vest immediately in
the event of certain changes in control of the Company. The number of
options has been adjusted to reflect a 3-for-1 stock split effective
in 1997.

(4) The exercise price of the HCRC options is $6.67 per share. The closing
price of the common stock was $23.17 on December 31, 1996. The number
of options and the exercise and closing price have been adjusted to
reflect a 3-for-1 stock split effective in 1997.

LONG-TERM INCENTIVE PLAN

The following table describes performance units awarded to the
executive officers of Hallwood G.P. for 1996 under the Incentive Plan (as
described below) for the Partnership and affiliated entities. The value of
awards under each plan depends primarily on the Partnership's success in
drilling, completing and achieving production from new wells each year and from
certain recompletions and enhancements of existing wells.

Long-term Incentive Plan Awards in Last Fiscal Year

<TABLE>
<CAPTION>
Performance or Estimated Future
Number of Other Period Payouts under Non-Stock
Name Units Until Payout Price-Based Plans(1)
---- ------- -------------- ---------------------
<S> <C> <C> <C>
Anthony J. Gumbiner(2) -- -- $ - -

William L. Guzzetti 0.0841 2001 25,835

Russell P. Meduna 0.0841 2001 25,835

Robert S. Pfeiffer 0.0580 2001 17,817

Cathleen M. Osborn 0.0580 2001 17,817
</TABLE>

- -----------------------
(1) This amount represents an award under the Incentive Plan. There are
no minimum, maximum or target amounts payable under the Incentive
Plan. Payments under the awards will be equal to the indicated
percentage of Plan net cash flow from certain wells for the first five
years after an award and, in the sixth year, the indicated percentage
of 80% of the remaining net present value of estimated future
production from the wells allocated to the Plan. The amounts shown
above are estimates based on estimated reserve quantities and future
prices. Because of the uncertainties inherent in estimating
quantities of reserves and prices, it is not possible to predict cash
flow or remaining net present value of estimated future production
with any degree of certainty.

(2) In addition, an award of .4200 units, with an estimated future payout
of $129,024, was made to HSC Financial, with which Mr. Gumbiner is
associated. The payout period ends in 2001.

The Incentive Plan for the Partnership and its affiliated entities,
including HCRC, is intended to provide incentive and motivation to HPI's key
employees to increase the oil and gas reserves of the various affiliated
entities for which HPI provides services and to enhance those entities' ability
to attract, motivate and retain key employees and consultants upon whom, in
large measure, those entities' success depends.

Under the Incentive Plan, the Board of Directors of Hallwood G.P. (the
"Board") annually determines the portion of the Partnership's collective
interests in the cash flow from certain international projects and from
domestic wells drilled, recompleted or enhanced during that year (the "Plan
Year") which will be allocated to participants in the plan and the percentage
of the remaining net present value of estimated future production from domestic
wells for which the participants will receive payment in the sixth year of an
award. The portion allocated to participants in the plan is referred to as the
Plan Cash Flow. The Board then determines which key employees and consultants
may participate in

59
<PAGE> 64
the plan for the Plan Year and allocates the Plan Cash Flow among the
participants. Awards under the plan do not represent any actual ownership
interest in the wells. Awards are made in the Board's discretion.

Each award under the Incentive Plan represents the right to receive
for five years a specified share of the Plan Cash Flow attributable to certain
domestic wells drilled, recompleted or enhanced during the Plan Year. In the
sixth year after the award, the participant is paid an amount equal to a
specified percentage of the remaining net present value of estimated future
production from the wells and the award is terminated. Cash flow from
international projects, if any, allocated to the Incentive Plan is paid to
participants for a 10-year period, with no buy-out for estimated future
production.

The awards for the 1996 Plan Year were made in January 1996. No other
awards were made in 1996. Awards for the 1997 Plan were made in March 1997.
The estimated future payouts under the 1997 awards will be calculated based on
estimates of the Partnership's revenues at December 31, 1997. For both the
1996 and 1997 Plan Years, the Compensation Committee of Hallwood G.P.
determined that the total Plan Cash Flow would be equal to 2.4% of the cash
flow of the domestic wells completed, recompleted or enhanced during each Plan
Year. Accordingly, the value of awards for each Plan Year depends primarily on
the Partnership's success in drilling, completing and achieving production from
new wells each year and from certain recompletions and enhancements of existing
wells. The Compensation Committee also determined that the participants'
interests in eligible domestic wells for the 1996 and 1997 Plan Years would be
purchased in the sixth year at 80% of the remaining net present value of the
wells completed in the Plan Years. The Compensation Committee also determined
that the total award would be allocated among key employees primarily on the
basis of salary, to the extent of 70% of the total award, and on individual
performance, to the extent of 30% of the total award.

DIRECTOR COMPENSATION

Each director of Hallwood G.P. who is not an officer of Hallwood G.P.
or HCRC or an employee of HPI, is paid an annual fee of $20,000 that is
proportionately reduced if the director attends fewer than four regularly
scheduled meetings of the Board during the year. During 1996, Messrs.
Holinger, Sebastian and Collins were each paid $20,000. In addition, all
directors are reimbursed for their expenses in attending meetings of the Board
and committees.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The Board of Directors of Hallwood G.P. makes compensation decisions
for the Partnership during the first quarter of each year. Mr. Gumbiner is
Chief Executive Officer of Hallwood G.P. and serves on the compensation
committee of Hallwood Group, of which Mr. Troup is President and Mr. Guzzetti
is Executive Vice President. Mr. Gumbiner is also Chief Executive Officer and
a director of HCRC, of which Mr. Troup is a director and Mr. Guzzetti is a
director and President. Messrs. Gumbiner, Troup and Guzzetti served on HCRC's
Board of Directors which made compensation decisions for HCRC in January 1996.
Mr. Gumbiner is Chief Executive Officer and a director, and Mr. Guzzetti is
President and a director, of Hallwood Realty. During 1996, Mr. Gumbiner and
Mr. Guzzetti served on the compensation committee of Hallwood Realty.

The Partnership participates in a financial consulting agreement
between HPI and Hallwood Group, pursuant to which Hallwood Group furnishes
consulting and advisory services to HPI, the Partnership and their affiliates.
Under the terms of this agreement, HPI and its affiliates are obligated to pay
Hallwood Group $550,000 per year until June 30, 2000. The agreement
automatically renews for successive three year terms; either party may
terminate the agreement on not less than 30 days written notice prior to the
expiration of any three year term. The financial consulting agreement replaced
both a previous financial consulting agreement and a compensation agreement
with Mr. Gumbiner. Under the terms of the previous financial consulting
agreement, HPI and its affiliates were obligated to pay Hallwood Group three
annual payments of $300,000 beginning June 30, 1994, and Hallwood Group was
obligated to furnish consulting and advisory services to HPI and its affiliates
through June 30, 1997. In 1996, the consulting services were provided by HSC
Financial Corporation, through the services of Mr. Gumbiner and Mr. Troup, and
Hallwood Group paid the annual fee it received to HSC Financial. A fee of
approximately $158,850 was paid in 1996 by the Partnership pursuant to this
arrangement. For 1994, 1995 and 1996, Mr. Gumbiner had a compensation
agreement with HPI pursuant to which Mr. Gumbiner was paid $250,000 by HPI, the
Partnership and their affiliates. This agreement was terminated effective
December 31, 1996. See "Summary Compensation Table" and footnotes for
additional discussion of this arrangement.

60
<PAGE> 65
The Partnership reimburses Hallwood Group for expenses incurred on
behalf of the Partnership. In 1996, the Partnership reimbursed Hallwood Group
approximately $152,000 of expenses.

61
<PAGE> 66
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

HPI performs all operations on behalf of the Partnership, and the
Partnership reimburses HPI at its cost for direct and indirect expenses
incurred by HPI for the benefit of the Partnership and its properties. The
indirect expenses for which HPI is reimbursed include employee compensation,
office rent, office supplies and employee benefits. The Partnership generally
allocates these expenses by multiplying the aggregate amount of the indirect
expenses incurred by HPI by the estimated time that the employees of HPI spend
on managing the Partnership and dividing by the aggregate time that the
employees of HPI spend on all the entities that HPI manages. The allocation of
certain components of employee compensation also takes into account the
Partnership's performance relative to its affiliates and the Partnership's
ownership interest in certain wells. HPI does not receive any fee for its
services. In 1996, the Partnership reimbursed HPI approximately $1.9 million
for direct and indirect expenses, not including payments and reimbursements to
Hallwood Group discussed below.

The majority of the Partnership's oil and gas properties are managed
and operated by HPI. HPI also manages and operates oil and gas properties on
behalf of independent joint interest owners and affiliates. In its capacity as
manager and operator, HPI pays all costs and expenses of operations and
distributes all revenues associated with the properties.

The Partnership Agreement provides that the General Partner will
receive an acquisition fee in cash or Units equal to 2% of the fair market
value of the total consideration paid in the acquisition of oil and gas
properties and related assets. In 1996, the Partnership paid the General
Partner total acquisition fees of $294,483 in cash. The Partnership Agreement
also provides that the General Partner is to receive a 4% interest in all oil
and gas properties and related assets acquired by the Partnership, with certain
exceptions. Pursuant to this provision, in 1996, the General Partner received
interests valued at $540,000.

Under the Partnership Agreement, the General Partner also receives a
direct or indirect interest in all wells drilled by the Partnership through its
1% interest in the Partnership. See "Description of Partnership
Agreements--Allocations of Profits and Losses--The Partnership"; "--Allocation
of Profits and Losses--HEPO"; and "Allocations of Profits and Losses--EDPO."
The interests received by the General Partner pursuant to these provisions in
1996 had a standardized measure of discounted future net cash flows at December
31, 1996 of $965,000.

The Partnership participates with HCRC in substantially all of its oil
and gas projects, generally on a 50/50 basis, unless the project is
inconsistent with either entity's objectives or the entities already have
differing interests in the project. During 1996, all projects were undertaken
jointly by the Partnership and HCRC on this basis.

Under a financial consulting agreement with HPI, Hallwood Group or its
agent furnishes consulting and advisory services to HPI, the Partnership and
their affiliates. Under the terms of the consulting agreement, HPI and its
affiliates are obligated to pay Hallwood Group $550,000 per year until June 30,
2000. The agreement automatically renews for successive three-year terms;
either party may terminate the agreement on not less than 30 days written
notice prior to the expiration of any three-year term. Under the terms of a
previous financial consulting agreement containing substantially the same
terms, HPI and its affiliates were obligated to pay Hallwood Group three annual
payments of $300,000 beginning June 30, 1994, and Hallwood Group was obligated
to furnish consulting and advisory services to HPI and its affiliates through
June 30, 1997. In 1996, the consulting services were provided by HSC Financial
Corporation, through the services of Mr. Gumbiner and Mr. Troup, and Hallwood
Group paid the annual fee it received to HSC Financial. A fee of approximately
$158,850 was paid in 1996 by the Partnership pursuant to this arrangement. For
1994, 1995 and 1996, Mr. Gumbiner also had a compensation agreement with HPI
pursuant to which Mr. Gumbiner was paid $250,000 by HPI, the Partnership and
their affiliates. The amount of consulting fees allocated to the Partnership
under this agreement was $125,000 in both 1996 and 1995 and $62,500 in 1994.
This agreement was terminated effective December 31, 1996.

The Partnership also reimburses Hallwood Group for expenses incurred
on behalf of the Partnership. In 1996, the Partnership reimbursed Hallwood
Group approximately $152,000 of expenses.

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<PAGE> 67
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES

GENERAL

Certain conflicts of interest exist and may arise in the future as a
result of the General Partner's relationships with its affiliates, on the one
hand, and the Partnership and the holders of the Units, on the other hand.
Hallwood G.P., as the general partner of HEPGP, has a fiduciary duty to manage
the Partnership in a manner that is in the best interest of the Unitholders.
The officers and directors of Hallwood G.P. have fiduciary duties to the
shareholders of Hallwood G.P. and to manage the General Partner in the best
interests of HEPGP's partners, Hallwood G.P. and Hallwood Group. In addition,
Messrs. Gumbiner, Troup and Guzzetti, directors and officers of Hallwood G.P.,
are directors and Messrs. Gumbiner and Guzzetti are executive officers of
Hallwood Group and, as such, owe a fiduciary duty to the shareholders of
Hallwood Group. Moreover, the officers of Hallwood G.P. are also officers or
directors of HCRC and, accordingly, owe a fiduciary duty to the shareholders of
HCRC. HCRC participates in oil and gas projects with the Partnership.
Consequently, the duties of Hallwood G.P. and its officers and directors to the
Unitholders of the Partnership may come into conflict with their duties to
other entities or investors. See "Management."

Conflicts of interest exist with respect to the situations described
below, among others:

The General Partner May Place Properties Within the Operating
Partnerships that are More Favorable to the General Partner

Because HEPO was formed at the same time and by the same general
partner as the Partnership, whereas EDPO was formed by a different general
partner and later acquired by the Partnership, the two Operating Partnerships
have different provisions regarding the manner in which the General Partner
participates in drilling conducted by that Operating Partnership. In HEPO, the
General Partner will be allocated 18.75% of revenues and costs attributable to
production and the Unitholders will be allocated 81.25%. In EDPO, the General
Partner generally is allocated 1% of all costs through completion of and 5% of
revenues from development wells and 10% of all costs through completion of and
25% of revenues from exploratory wells. The differences in allocation of costs
and revenues present the General Partner with a conflict of interest in
determining through which of the Operating Partnerships to acquire new drilling
locations. The Board of Directors of Hallwood G.P. has adopted a policy to
address this potential conflict of interest, providing generally that new wells
to be drilled by the Partnership in 14 West Texas counties, other than on
properties in which EDPO has an existing interest or that are contiguous to
properties in which EDPO has an existing interest, will be drilled in HEPO
through the joint venture with the General Partner, and that all other new
drilling will be done in EDPO.

The General Partner's Affiliates May Compete with the Partnership in
Certain Circumstances

Affiliates of the General Partner (including Hallwood Group and HCRC)
are not prohibited from engaging in any business or activity, even if such
activity may be in direct competition with the Partnership. Hallwood Group does
not presently engage in oil and gas activities other than through its interests
in Hallwood G.P., HEPGP, the Partnership and HCRC. HCRC, however, is actively
engaged in oil and gas production, development and exploration. To minimize
the conflicts of interest between the Partnership and HCRC, the Board of
Directors of each of Hallwood G.P. and HCRC has adopted a policy that each
Board will review annually participation by both the Partnership and HCRC in
new oil and gas properties. Generally the Partnership and HCRC will
participate on a 50/50 basis in all future oil and gas drilling projects,
leases, concessions or acquisitions, unless the activity is inconsistent with
either entity's objectives or the entities already have differing interests in
the subject property. This policy may change, however, if circumstances change
or the Board of Directors of Hallwood G.P. or HCRC determines it is not in such
entity's best interest.

Contracts Between the Partnership and the General Partner and Its
Affiliates Will Not Be the Result of Arm's- Length Negotiations

Under the terms of the Partnership Agreement, the Partnership is not
restricted from paying the General Partner or its affiliates for any services
rendered, provided such services are rendered on terms that are reasonable to
the Partnership. The Partnership Agreement does not specify who is to
determine whether the terms of transactions are reasonable. In practice, this
determination is made by management, under the supervision of the Board of
Directors of

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<PAGE> 68

the General Partner. Transactions between the Partnership and the General
Partner and its affiliates will not be the result of arm's-length negotiations.

Certain Actions Taken by the General Partner May Affect the Amount of
Cash Available for Distribution to Unitholders

Decisions of the General Partner with respect to the amount and timing
of cash expenditures, participation in capital expansions and acquisitions,
borrowings, issuances of additional partnership interests and reserves in any
quarter may affect whether, or the extent to which, there is available cash for
distributions on all Units in such quarter or in subsequent quarters. The
Partnership Agreement provides that the Partnership and the Operating
Partnerships may borrow funds from the General Partner and its affiliates,
provided that neither the General Partner nor its affiliates may charge
interest to the Partnership greater than the lesser of (i) the General
Partner's or its affiliate's actual interest cost or (ii) the rate that would
be charged to the Partnership by an unrelated lender on a comparable loan. The
General Partner and its affiliates may not borrow funds from the Partnership or
the Operating Partnerships.

The Partnership Will Reimburse the General Partner and Its Affiliates
for Certain Expenses

Under the terms of the Partnership Agreement, the General Partner and
its affiliates will be reimbursed by the Partnership for expenses incurred on
behalf of the Partnership, including costs incurred in providing corporate
staff and support services to the Partnership. The General Partner may
determine the expenses that are allocable to the Partnership in any reasonable
manner determined by the General Partner in its sole discretion.

Employees of the General Partner's Affiliates Who Provide Services to
the Partnership Will Also Provide Services to Other Businesses

The Partnership does not have any employees and relies on the
employees of HPI to manage the Partnership's affairs. Although the General
Partner will not conduct any other business, Hallwood Group, HCRC and other
affiliates of the General Partner or the Partnership will conduct business and
activities of their own in which the Partnership will have no economic interest
and which may also be conducted by HPI's employees. There may be competing
demands among the Partnership, Hallwood Group, HCRC and such affiliates for the
time and efforts of employees who provide services to more than one of these
entities.

ACQUISITION OF ADDITIONAL PROPERTIES AND CONDUCT OF EXPLORATORY AND DEVELOPMENT
DRILLING

The Partnership Agreement provides that the General Partner will
receive an acquisition fee in cash or Units equal to 2% of the fair market
value of the total consideration paid in the acquisition of oil and gas
properties and oil and gas related assets by the Partnership, including
acquisitions of such oil and gas interests through the acquisition of stock of
corporations and similar transactions. If the acquisition fee is paid in
Units, the number of Units to be received by the General Partner will be
determined by dividing the average market price of the Units for the five
business days immediately preceding the date of the acquisition into an amount
equal to 2% of the acquisition cost of such assets. With respect to
acquisitions of oil and gas properties and oil and gas related assets other
than Undeveloped Acreage and Proved Undeveloped Acreage (as such terms are
defined in the Partnership Agreement), including acquisitions of such oil and
gas interests through the acquisition of stock of corporations and similar
transactions and as an incentive for the General Partner to make acquisitions
of oil and gas properties and oil and gas related assets on behalf of the
Partnership, the General Partner also will receive 4% of the interest acquired
by the Partnership and the Operating Partnerships in such assets. The General
Partner's interest in the foregoing fees may result in conflicts of interest as
to whether the Partnership should engage in any activity or acquire a property.

FIDUCIARY AND OTHER DUTIES

The General Partner is accountable to the Partnership and the
Unitholders as a fiduciary. Consequently, the General Partner must exercise
good faith and integrity in handling the Partnership's assets and affairs. In
contrast to the relatively well-developed law concerning fiduciary duties owed
by officers and directors to the stockholders of a corporation, the law
concerning the duties owed by general partners to other partners and to
partnerships is relatively undeveloped. Neither the Delaware Revised Uniform
Limited Partnership Act ("Delaware Act") nor Delaware case law

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<PAGE> 69
defines with particularity the fiduciary duties owed by general partners to
limited partners or a limited partnership, but the Delaware Act provides that
Delaware limited partnerships may, in their partnership agreements, restrict or
expand the fiduciary duties that might otherwise be applied by a court in
analyzing the duties owed by general partners to limited partners and the
partnership.

Fiduciary duties are generally considered to include an obligation to
act with the highest good faith, fairness and loyalty. Such duty of loyalty,
in the absence of a provision in a partnership agreement providing otherwise,
would generally prohibit a general partner of a Delaware limited partnership
from taking any action or engaging in any transaction as to which it has a
conflict of interest. In order to induce the General Partner to manage the
business of the Partnership, the Partnership Agreement, as permitted by the
Delaware Act, contains various provisions that may restrict the fiduciary
duties that might otherwise be owed by the General Partner to the Partnership
and its Unitholders, and waiving or consenting to conduct by the General
Partner and its affiliates that might otherwise raise issues as to compliance
with fiduciary duties or applicable law.

The Partnership Agreement provides that, in order to become a limited
partner of the Partnership, a holder of Class C Units is required to agree to
be bound by the provisions thereof, including the provisions discussed above.
This is in accordance with the policy of the Delaware Act favoring the
principle of freedom of contract and the enforceability of partnership
agreements. The Delaware Act also provides that a partnership agreement is not
unenforceable by reason of its not having been signed by a person being
admitted as a limited partner or becoming an assignee in accordance with the
terms thereof.

Under the terms of the Partnership Agreement, the Partnership is
required to indemnify the General Partner, its affiliates and their respective
officers, directors, employees, affiliates, partners, agents and trustees, to
the fullest extent permitted by law, against liabilities, costs and expenses
incurred by the General Partner or such other persons, if the General Partner
or such persons acted in good faith and in a manner they reasonably believed to
be in, or not opposed to, the best interests of the Partnership and, with
respect to any criminal proceedings, had no reasonable cause to believe the
conduct was unlawful. See "Description of The Partnership
Agreements--Indemnification." Thus, the General Partner could be indemnified
for its negligent acts if it meets such requirements concerning good faith and
the best interests of the Partnership. Further, the Partnership Agreement
provides that the General Partner, its affiliates and their respective
officers, directors, employees, affiliates, agents, and trustees will not be
liable for monetary damages to the Partnership, the limited partners or
assignees for errors of judgment or for any acts or omissions if the General
Partner and such other persons acted in good faith.

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PRINCIPAL UNITHOLDERS

The following table shows information, as of December 10, 1997, about
any individual, partnership or corporation that is known to the Partnership to
be the beneficial owner of more than 5% of each class of Units issued and
outstanding and each executive officer and director of Hallwood G.P. and all
executive officers/directors as a group.

<TABLE>
<CAPTION>
Prior to Offering Subsequent to Offering(1)
--------------------- -------------------------

Amount Percent Amount Percent
Title of Beneficially of Beneficially of
Name and Address of Owner Class Owned Class Owned Class
- ------------------------- ------- ----- ------- ----- -------

<S> <C> <C> <C> <C> <C>
The Hallwood Group Incorporated Class A Units (2) 657,260 6.5 657,260 6.5
3710 Rawlins Street, Suite 1500 Class B Units 143,773 100.0 143,773 100.0
Dallas, Texas 75219 Class C Units 43,816 6.6 43,816 1.4

Hallwood Consolidated Resources Class A Units 1,948,189 19.5 1,948,189 19.5
Corporation Class C Units 129,877 19.6 129,877 4.1
4582 S. Ulster Street Parkway
Suite 1700
Denver, Colorado 80237

Heartland Advisors, Inc. Class A Units (3) 1,045,500 10.5 1,045,500 10.5
790 North Milwaukee Street
Milwaukee, WI 53202

William Baxter Lee, III Class A Units (4) 707,000 7.1 707,000 7.1
c/o Glankler Brown, PLLC Class C Units (4) 37,000 5.6 37,000 1.2
1700 One Commerce Sq.
Memphis, TN 38103

Anthony J. Gumbiner Class A Units 127,500 1.3 127,000 *

William L. Guzzetti Class A Units 63,850 * 63,850 *
Class C Units 6 * 6 *

Russell P. Meduna Class A Units 59,500 * 59,500 *

Cathleen M. Osborn Class A Units 25,500 * 25,500 *

Robert Pfeiffer Class A Units 25,803 * 25,803 *
Class C Units 20 * 20 *

Brian M. Troup Class A Units 85,000 * 85,000 *

Hans-Peter Holinger -- -- -- -- --

Rex A. Sebastian Class A Units 400 * 400 *
Class C Units 26 * 26 *

Nathan C. Collins -- -- -- -- --

All directors and executive officers Class A Units (5) 387,553 3.7 387,553 3.7
as a group (9 persons) Class C Units 52 * 52 *

</TABLE>

- -------------------------------
* Less than 1%.

(1) Assuming the sale of 2,500,000 Class C Units in the Offering.

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<PAGE> 71

(2) Includes 143,773 Class B Units (100% of the Class B Units)
that are convertible into Class A Units one- for-one.
(3) According to the Amendment to Schedule 13G filed February 14,
1997 by Heartland Advisors, Inc., the Units to which the
schedule relates are held in investment advisory accounts of
Heartland Advisors, Inc. As a result, various persons have
the right to receive or the power to direct the receipt of
dividends from, or the proceeds from the sale of, the
securities. No such account is known to have an interest
relating to more than 5% of the class.
(4) According to Schedules 13D dated November 26, 1997.
(5) Consists of 803 Class A Units and currently exercisable
options to purchase 386,750 Class A Units.

DESCRIPTION OF CLASS C UNITS

GENERAL

Class C Units are units of limited partner interest in the
Partnership. Registrar & Transfer Co. acts as transfer agent for the Class C
Units (the "Transfer Agent"). The Class C Units are represented by
certificates in registered form. Unitholders may hold Class C Units in nominee
accounts for the account of another person, provided that the nominee certifies
to the Transfer Agent that it is, and to the best of its knowledge such person
is, a United States Citizen (as defined in the Partnership Agreement, see
"Glossary of Certain Terms"). Each Class C Unit is freely transferable to
United States Citizens, except as restricted by federal and state securities
laws.

The Class C Units are registered under the Exchange Act, and the
Partnership is subject to the reporting and proxy solicitation requirements of
the Exchange Act and the rules and regulations thereunder. The Partnership is
required to file periodic reports containing financial and other information
with the SEC.

The Class C Units are entitled to a preferential distribution of $1.00
per Class C Unit per annum, payable quarterly to holders of record on March 31,
June 30, September 30 and December 31 in each year. The Class C preferential
distribution is cumulative, and no distributions may be paid or declared on
Class A or Class B Units unless all accrued and unpaid distributions on the
Class C Units have been paid or declared and duly provided for. As of October
24, 1997, there were 664,063 Class C Units outstanding.

TRANSFER OF CLASS C UNITS

Class C Units are securities and are transferable to United States
Citizens according to the laws governing transfer of securities. In addition
to other rights acquired upon transfer, the transferor gives the transferee who
is a United States Citizen the right to seek admission as a substituted limited
partner (a "Substituted Limited Partner") in the Partnership in respect of the
transferred Class C Units. A record holder of a Class C Unit, however, will
only have the authority to convey to a purchaser or other transferee who is not
a United States Citizen the right to sell the Class C Unit.

Until a Class C Unit has been transferred on the books of the Transfer
Agent, the Transfer Agent and the Partnership will treat the record holder
thereof as the absolute owner for all purposes. A transfer of a Class C Unit
will not be registered by the Transfer Agent or recognized by the Partnership
unless the transferee executes a Transfer Application ("Transfer Application")
and certifies therein that the transferee and, if the transferee is a nominee
holding for the account of another person, that to the best of its knowledge
such other person, is a United States Citizen. By executing the Transfer
Application, the transferee requests admission as a Substituted Limited Partner
and agrees to be bound by the terms and conditions of the Partnership
Agreement, including the grant of a limited power of attorney to the General
Partner. Whether or not a transferee executes the Transfer Application, a
transferee, by acceptance of the Class C Unit, becomes a party to the
Partnership Agreement, bound by its terms and conditions, and agrees that his
transferor has no liability or responsibility if such transferee neglects or
chooses not to execute and forward the Transfer Application. A transferee will
become a Substituted Limited Partner, effective upon such consent by the
General Partner. The transferee of a Class C Unit, pending admission as a
Substituted Limited Partner, will have the rights of an assignee under state
law was its execution of a Transfer Application.

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<PAGE> 72
STATUS AS A LIMITED PARTNER OR ASSIGNEE

A transferee of a Class C Unit, in order to be registered on the books
of the Transfer Agent as the record holder, must execute a Transfer Application
and certify that the transferee is a United States Citizen. A transferee who
does not execute a Transfer Application and certify that he is a United States
Citizen will not become a Substituted Limited Partner in the Partnership and
will acquire no rights in the Partnership other than the right to transfer his
Class C Units to a third person who, upon execution of a Transfer Application
and certification that such third person is a United States Citizen, may become
a Substituted Limited Partner of the Partnership. Until such time as a
transferee is admitted as a Substituted Limited Partner of the Partnership, the
assignor Limited Partner (as defined herein) will continue to possess the right
to exercise the voting and other rights with respect to the Class C Units
transferred. By executing a Transfer Application and accepting a Class C Unit,
transferees of Class C Units will automatically request admission as a
Substituted Limited Partner in the Partnership, will agree to be bound by the
terms and conditions of the Partnership Agreement, will appoint the General
Partner as their attorney-in-fact and will, pending their admission as
Substitute Limited Partners, be granted the rights of an assignee under state
law.

An assignee is entitled to an interest in the Partnership equivalent
to that of a limited partner with respect to the right to share in
distributions from the Partnership, including liquidating distributions, but
without the right to vote directly on certain Partnership matters and otherwise
subject to the limitations under the Delaware Act on the rights of an assignee
who has not become a Substituted Limited Partner. Under the Partnership
Agreement, an assignee becomes a Substituted Limited Partner when the General
Partner so consents in its sole discretion. The General Partner is deemed to
consent to the admission of an assignee as the Substituted Limited Partner and
such admission is effective, as of the close of business at the offices of the
Transfer Agent on the day on which the transferee delivers an executed Transfer
Application to the Transfer Agent, unless the General Partner has previously
expressly withheld such consent. If the General Partner's consent is
withheld, the assignee would be notified by the Transfer Agent and would
continue to be an assignee, with the rights granted to an assignee pursuant to
the Partnership Agreement. Transferees who do not execute a Transfer
Application will be treated neither as assignees nor as record holders of Class
C Units and will not receive cash distributions, federal income tax allocations
or reports furnished to record holders of Class C Units.

In the event the General Partner determines, with the advice of
counsel, that a Limited Partner or assignee is not a United States Citizen, the
Partnership may redeem the Class C Units held by such person for the then
current market price of such Units.

DUTIES AND STATUS OF TRANSFER AGENT

The Transfer Agent will act as a registrar and transfer agent for the
Class C Units, and will receive an annual fee from the Partnership for serving
in such capacities. All fees charged by the Transfer Agent for transfers of
Class C Units will be borne by the Partnership and not by the Class C
Unitholders (except that fees similar to those customarily paid by stockholders
for surety bond premiums to replace lost or stolen certificates, tax or other
governmental charges, special charges for services requested by Class C
Unitholders and other similar fees or charges will be borne by the affected
Class C Unitholders). There will be no charge to Class C Unitholders for
disbursements of Partnership cash distributions.

DESCRIPTION OF THE PARTNERSHIP AGREEMENTS

The following information, as well as the information included
elsewhere in this Prospectus concerning the Partnership Agreement and the
Operating Partnership Agreements, is subject to the detailed provisions of the
Partnership Agreement and the Operating Partnership Agreements, as amended.
The Partnership Agreement and the Operating Partnership Agreements are included
as exhibits to the Registration Statement of which this Prospectus is a part.
Copies of the Partnership Agreement and the Operating Partnership Agreements
may be obtained by a written or oral request directed to Hallwood Energy
Partners, L.P., Attention: Investor Relations, 4582 South Ulster Street
Parkway, Suite 1700, Denver, Colorado 80237, telephone number (800) 882-9225.

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The provisions governing the Partnership and the Operating
Partnerships are complex and extensive, and no attempt has been made below to
describe all of such provisions. The following is a general description of the
basic provisions of the Partnership Agreement and the Operating Partnership
Agreements.

ORGANIZATION AND DURATION

The Partnership and the Operating Partnerships are each organized as a
Delaware limited partnership. HEPGP is the general partner of all three
partnerships (the "General Partner") and holds a 1% general partner's interest
in each of the Partnership and HEPO and a varying general partner interest in
EDPO, see "--Allocation of Profits and Losses--EDPO." The Class A Unitholders,
Class B Unitholders and Class C Unitholders (including HEPGP in its capacity as
a Unitholder) collectively hold a 99% interest in the Partnership. Income and
losses are allocated among Unitholders as described in "--Allocation of Profits
and Losses--The Partnership," below. Each class of Unitholders votes
separately as a class on all matters submitted to Unitholders. The Partnership
holds a 99% interest as the sole limited partner in HEPO and an interest as the
sole limited partner in EDPO.

The Partnership and the Operating Partnerships will terminate on
December 31, 2035, unless sooner dissolved.

MANAGEMENT

As General Partner, HEPGP will exercise full control over all
activities of the Partnership and Operating Partnerships and, with certain
exceptions provided in the respective partnership agreements, all management
powers over and control of the business and affairs of the partnerships will be
vested in the General Partner. HEPGP's authority as General Partner is,
however, limited in certain respects. The General Partner is prohibited,
without the prior approval of holders of a majority-in-interest
("Majority-In-Interest") of the Limited Partners, from, among other things, (i)
selling or exchanging all or substantially all of the Partnership's assets or,
acting on behalf of the Partnership, consenting to the sale of all or
substantially all of the Operating Partnerships' assets, or (ii) amending the
Partnership Agreement or acting on behalf of the Partnership, consenting to
amendments to the Operating Partnership Agreements, except for certain
amendments described below under "Description of the Partnership
Agreements--Amendment of Partnership Agreement and Operating Partnership
Agreements." Any amendment to a provision of the Partnership Agreement that
would adversely affect the interests of the limited partners of the Partnership
(the "Limited Partners") in any material respect will require the approval of
the holders of a Majority-In-Interest of the Limited Partners. Any action
requiring approval by a Majority-in-Interest of the Limited Partners will
require approval by holders of a majority of the holders of each of the Class A
Units, the Class B Units and Class C Units, each voting separately as a class.
Hallwood Group holds all the Class B Units and, therefore, may veto any action
requiring the approval by a Majority-in- Interest of the Limited Partners.

The General Partner of the Partnership may be removed by the
affirmative vote of at least two-thirds in interest of each class of
Unitholders, subject in each case to the selection of a successor general
partner and receipt of an opinion of counsel that such removal and the
selection of a successor general partner would not result in the loss of the
limited liability of the Limited Partners or the Partnership (as the limited
partner of an Operating Partnership) or cause the Partnership or any Operating
Partnership to be treated as an association taxable as a corporation for
federal income tax purposes. The withdrawal or removal of the general partner
of the Partnership will also constitute the withdrawal or removal of the
general partner of the Operating Partnerships and the appointment of the person
elected as successor general partner of the Partnership as the successor
general partner of the Operating Partnerships. Hallwood Group holds all of the
outstanding Class B Units, which vote separately as a class on all matters
brought for a vote of the Limited Partners and which, therefore, will enable
Hallwood Group to prevent the adoption of any proposal to remove HEPGP as
General Partner.

In the event of withdrawal or removal, the successor general partner
will have the option to acquire the departing General Partner's respective
general partner's interests in the Partnership and the Operating Partnerships
for a cash payment equal to the fair market value (based on the price at which
Units are then trading, or if not so trading, by agreement with the successor
general partner or, failing agreement, as determined by a firm of independent
petroleum engineers selected pursuant to the terms of the Partnership
Agreement) of its respective general partner's interests in the partnerships.
The option must be exercised, if at all, as to the interests of the General
Partner in both the Partnership and the Operating Partnerships. If the option
is not exercised, the General Partner's interest in each of the Partnership and

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the Operating Partnerships will be converted into limited partnership interests
in the Partnership. Any successor general partner not exercising the option
will be required, at the effective date of its admission to the Partnership, to
contribute to the capital of the Partnership cash or property having a value
calculated pursuant to the provisions of the Partnership Agreement.
Thereafter, such successor shall be entitled to 1.0% of all Partnership
allocations and distributions.

With the consent of a Majority-In-Interest of each class of
Unitholders and upon receipt of an opinion of independent counsel that such
transfer would not result in the loss of the limited liability of the Limited
Partners or the Partnership (as the limited partner of the Operating
Partnerships) or cause the Partnership or any Operating Partnership to be
treated as an association taxable as a corporation for federal income tax
purposes, the General Partner may transfer its interest as general partner of
the Partnership and the Operating Partnerships to a transferee certifying that
it is a United States Citizen. Without the consent of the Limited Partners,
the General Partner may transfer its interest as general partner of the
Partnership or the Operating Partnerships upon its merger or consolidation with
or into another entity or upon the transfer of all or substantially all of its
assets to another entity, provided such entity furnishes the above-described
opinion of independent counsel, certifies that it is a United States Citizen
and assumes the rights and duties of the General Partner.

Each Limited Partner, and each person who becomes a Substituted
Limited Partner, grants to the General Partner a power of attorney to execute
and file certain documents required in connection with the qualification,
continuance or dissolution of the Partnership, other federal or state
governmental filings, as necessary, and the amendment of the Partnership
Agreement.

The General Partner may form operating partnerships (in addition to
the Operating Partnerships) on substantially the same terms as the Operating
Partnerships, in each of which the General Partner or an affiliate will act as
general partner and the Partnership will be a limited partner.

ALLOCATION OF PROFITS AND LOSSES - THE PARTNERSHIP

In general, each item of income, gain, loss, deduction and credit of
the Partnership is allocated 99% to the Unitholders and 1% to HEPGP. The
descriptions of the allocations of profits and losses from HEPO and EDPO below
give effect to this provision of the Partnership Agreement. Operating income
generally will be allocated first, to the holders of Class C Units to the
extent of the operating losses and deductions allocated to such holders;
second, to the holders of the Class C Units to the extent of their aggregate
preference amount (whether or not actually distributed); and third, to the
holders of the Class A and Class B Units, pro rata in accordance with their
percentage interests. All amounts to be allocated to the Unitholders as a
class (A, B or C) will be allocated between the Unitholders in accordance with
their respective percentage interests in the Partnership. Gain from a
terminating capital transaction generally will be allocated first to the
holders of the Class C Units until their positive capital account balances are
equal to their unpaid preference amounts and then to the holders of the Class
A, Class B and Class C Units, pro rata in accordance with their percentage
interests.

The Class C units are entitled to a preferential distribution of $1.00
per Class C Unit per annum, payable quarterly to holders of record on March 31,
June 30, September 30 and December 31 in each year. The Class C preferential
distribution is cumulative, and no distributions may be paid or declared on
Class A or Class B Units unless all accrued and unpaid distributions on the
Class C Units have been paid or declared and duly provided for. Operating
distributions generally will be made first to the holders of Class C Units to
the extent of their unpaid preference amounts and then to the holders of the
Class A and Class B Units, in accordance with their percentage interests, as
follows: (i) during any calendar quarter in which distributions on the Class A
Units are equal to $0.20 or more, the Class B Units have equal distribution
rights with the Class A Units and (ii) during any calendar quarter in which the
distributions on the Class A Units are less than $0.20 per Class A Unit, no
cash distribution will be made in connection with the Class B Units; provided,
however, the amount that would have otherwise been payable may be recouped in
any quarter that the Class A Unitholders (including the Class B Unitholders)
receive current distributions equal to or greater than $0.20 per Unit per
quarter. Liquidation proceeds, after all payments are made to the
Partnership's creditors, will be made to the Unitholders to the extent of and
in proportion to the positive balances of their respective capital accounts.

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ALLOCATION OF PROFITS AND LOSSES - HEPO

Subject to certain exceptions discussed below, Partnership revenues
and costs attributable to production from producing oil and gas wells
("Producing Properties") owned by HEPO will be allocated 98.01% to the
Unitholders (including HEPGP in its capacity as a Unitholder) and 1.99% to
HEPGP as General Partner. All revenues derived from the sale or other
disposition of Producing Properties will be allocated 98.01% to the Unitholders
and 1.99% to HEPGP as General Partner. The General Partner has the obligation
to contribute an amount equal to 1% of the total contributions to HEPO from
time to time.

The partnership agreement for HEPO provides that all drilling
conducted by HEPO will be done through a joint venture with the General Partner
of HEPO that provides for an allocation of profits and losses between the
General Partner and HEPO. Accordingly, the allocations of profits and losses
from drilling activities described in this paragraph and the following
paragraph give effect to the joint venture agreement, as well as the
partnership agreements of HEP and HEPO. All revenues and all operating costs
and general and administrative costs attributable to future drilling activities
on properties that are not Producing Properties ("Non-Producing Properties")
will be allocated 79.63% to the Unitholders and 20.37% to the general partner.
All costs, other than operating costs and general and administrative costs,
including the costs attributable to the acquisition, drilling and completing of
Non-Producing Properties, will be allocated 90.66% to the Unitholders and 9.34%
to the General Partner.

All revenues derived from the sale or other disposition of a
Non-Producing Property (other than depreciable equipment) having a book basis
will be allocated to the partners of the Partnership in the ratio in which the
costs of acquiring such property was allocated to the extent of such basis and
any excess revenues will be allocated first, to HEPGP until such allocation
equals 20% of the carrying value of such Non-Producing Property prior to the
disposition and then any remaining revenues will be allocated in the ratio of
79.63% to the Unitholders and 20.37% to the general partner. Revenues and
costs that are allocable to depreciable equipment during the first five years
such property is placed in service will be, in general, allocated 90.66% to the
Unitholders and 9.34% to the General Partner, with revenues derived from the
sale of equipment after the five-year period allocated 79.63% to the
Unitholders and 20.37% to the general partner.

ALLOCATION OF PROFITS AND LOSSES - EDPO

The provisions of the EDPO Partnership Agreement generally are the
same as the provisions of the HEPO Partnership Agreement, except (i) the
General Partner of EDPO will have no obligation to make additional capital
contributions upon the making of additional capital contributions by the
Partnership, (ii) the Partnership has an obligation to restore any negative
balance in its capital account upon the liquidation of EDPO, (iii) drilling
conducted by EDPO is not conducted through a joint venture, and (iv) to the
extent discussed below, the combined effect of the allocation of EDPO's
revenues and costs to the Partnership and HEPGP and the Partnership's
allocation of revenues and costs to the Unitholders and HEPGP will be different
from the combined effect of the allocation of HEPO's revenues and costs to the
Partnership and HEPGP and the Partnership's allocation of revenues and costs to
the Unitholders and HEPGP.

Generally, the general partner is allocated 2% of each item of cost
and revenue, and the remainder is allocated to the Partnership. With respect
to productive wells located on, or production from which is attributable to,
properties other than those acquired by EDPO in connection with its inception
in 1985 (the "Other Properties") and that were acquired before May 9, 1990, 5%
of the costs and revenues attributable to such Productive Wells will be
allocated to the general partner and the remainder of such costs and revenues
shall be allocated to the Partnership.

With respect to each development well drilled that is located on, or
production from which is attributable to, the properties acquired by EDPO in
connection with its inception in 1985 ("Initial Properties") and each
development well that is located on, or production from which is attributable
to, the Other Properties and that is drilled after the date of acquisition by
the Partnership of an interest in such well (i) 99% of the costs through
completion attributable to such development well will be allocated to the
Unitholders and 1% to the General Partner and (ii) 5% of all other costs and
revenues attributable to such development wells will be allocated to the
General Partner and the remainder of such costs and revenues shall be allocated
to the Unitholders.

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With respect to each exploratory well drilled that is located on, or
production from which is attributable to, the Initial Properties and each
exploratory well that is located on, or production from which is attributable
to, the Other Properties and that is drilled after the date of acquisition by
the Partnership of an interest in such well, (i) 10% of the costs through
completion attributable to such exploratory well will be allocated to the
General Partner and the remainder of such costs through completion will be
allocated to the Unitholders, and (ii) 25% of all other costs and revenues
attributable to such exploratory well will be allocated to the general partner
and the remainder of such costs and revenues will be allocated to the
Unitholders.

ALLOCATION OF INCOME TAX ITEMS

In general, tax deductions and credits will be allocated in the same
manner in which the related costs are allocated and taxable income will be
allocated in the same ratio in which revenue is allocated (excluding revenues
that represent a return of basis). However, the adjusted tax basis of
depletable property is allocated in a manner to take into account the variation
between the basis of contributed property to the Partnership and its fair
market value at the time of contribution. The intent of these allocations is
to effect the allocations required by section 704(c) of the Code. See
"Material Federal Income Tax Considerations--General Features of Partnerships
Taxation--Tax Allocations."

DISTRIBUTIONS

The General Partner will review the Partnership's accounts on a
quarterly basis and make such distributions as it determines to be appropriate.

ADDITIONAL CLASSES OR SERIES OF UNITS; SALES OF OTHER SECURITIES

The General Partner is authorized to cause the Partnership to issue
Units from time to time to raise additional capital, to acquire assets, to
redeem or retire Partnership debt, to adopt fringe benefit plans for employees,
to comply with the provisions of an Operating Partnership Agreement or for any
other Partnership purpose. The total number of Units of all classes that may
be issued shall not exceed 100,000,000 plus any Units issued to a former
general partner upon conversion of his general partner interests in the
Partnership and the Operating Partnerships, to limited partner interests,
although such amount may be changed by amendment to the Partnership Agreement.
The General Partner has sole and complete discretion in determining the
consideration and terms and conditions with respect to any future issuance of
Units. The terms of the Partnership Agreement do not restrict the General
Partner's authority to cause the Partnership to issue Units in one or more
classes or series with such designations, preferences and relative,
participating, optional or other special rights including, without limitation,
preferential economic or voting rights, as shall be fixed by the General
Partner in the exercise of its sole and complete discretion; provided, however,
that all Units of every such class or series shall be identical to the Class A
Units, except as to the following relative rights and preferences as to which
there may be variations: (i) the allocation to such class or series of Units of
items of Partnership income, gain, loss, deduction and credit; (ii) the right
of such class or series of Units to share in Partnership distributions; (iii)
the rights of such class or series of Units upon dissolution and liquidation of
the Partnership; (iv) the price at and the terms and conditions on which such
class or series of Units may be redeemed by the Partnership, if such Units are
redeemable by the Partnership; (v) the rate at and the terms and conditions on
which such class or series of Units may be converted into any other class or
series of units if any class or series of Units is issued with the privilege of
conversion; and (vi) the right of any such class or series of Units to vote on
matters relating to the relative rights and preferences of such class. Because
the terms of any such Units may be established by the General Partner in its
sole discretion at the time of their issuance, the effect of such issuance on
holders of outstanding Units cannot be predicted. The issuance of any
additional class or classes or series of Units preferred to outstanding Units
as to any of such matters, however, may adversely affect holders of outstanding
Units to the extent of such preference. Upon the issuance of any class or
series of Units that shall not be identical to the Class A Units, the General
Partner may, without the consent of any Limited Partner, amend any provision of
the Partnership Agreement as shall be necessary or desirable to reflect the
issuance of such class or series of Units and the relative rights and
preferences of such class or series of Units as to the matters set forth in the
preceding sentence. The General Partner is also authorized to cause the
issuance of any other type of security of the Partnership from time to time to
partners or other persons on terms and conditions established in the sole and
complete discretion of the General Partner. Such securities may include,
without limitation, unsecured and secured debt obligations of the Partnership,
debt obligations of the Partnership convertible into any class or series of
Units that may be issued by the Partnership, options or warrants to purchase
any such class or series of Units or any combination of any of the foregoing.

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No partner of the Partnership has any preemptive, preferential or
other rights pursuant to the terms of the Partnership Agreement, as presently
in effect, with respect to any securities that may be issued or sold by the
Partnership.

A holder of Class B Units is entitled to convert each Class B Unit to
one publicly traded Class A Unit only upon certain conditions. Specifically,
Article XIX of the Partnership Agreement provides generally that the Class B
Units will be convertible for Class A Units on a one-for-one basis provided
that prior to such conversion the per Unit capital account of each Class B
Unitholder shall be adjusted so that it shall be equal to the capital account
of each Class A Unit. This adjustment may be required as a result of the
operation of the cash distribution subordination provisions of the Partnership
Agreement pursuant to which distributions to the Class B Unitholders may be
less than distributions to the Class A Unitholders. If, immediately prior to
the conversion of the Class B Units into Class A Units, the capital account per
Class B Unit is greater than the capital account per Class A Unit, the General
Partner, as a condition to conversion, must make an additional capital
contribution to the Partnership sufficient to enable the Partnership to make a
special distribution to the Class B Unitholders that is sufficient to cause the
capital account per Class B Unit to be the same as capital account per Class A
Unit. If, on the other hand, immediately prior to such conversion, the capital
account per Class B Unit is less than the capital account per Class A Unit,
each Class B Unitholder will be required to make an additional capital
contribution to the Partnership sufficient to make the capital account per
Class B Unit the same as the capital account per Class A Unit. Additionally, a
Class A Unit converted from a Class B Unit may not be transferred unless the
Partnership has a section 754 election in effect. See "Federal Income Tax
Considerations--Tax Consequences of the Partnership's Operations--Section 754
Election." The conversion rate is subject to adjustment in certain events,
such as distributions to all holders of Class A Units payable in any class of
Units and subdivisions, combinations and reclassifications of Class A Units.
During any calendar quarter in which distributions on the Class A Units are
equal to $0.20 or more, the Class B Units have equal distribution rights with
the Class A Units. During any calendar quarter in which the distributions on
the Class A Units are less than $0.20 per Class A Unit, no cash distribution
will be made connection with the Class B Units; however, the amount that would
have otherwise been payable to Class B Unitholders may be recouped in any
quarter that the Class A Unitholders (including the Class B Unitholders)
receive current distributions equal to or greater than $0.20 per Unit per
quarter. As a result of Hallwood Group's ownership of the Class B Units,
although Hallwood Group would not be able to approve any matters required to be
approved by Unitholders without the approval of the holders of a majority of
the Class A Units, Hallwood Group's ownership of the Class B Units would very
likely delay or prevent a hostile tender offer or other attempt to remove HEPGP
as General Partner or to effect any other change in control of the Partnership.

AMENDMENT OF PARTNERSHIP AGREEMENT AND OPERATING PARTNERSHIP AGREEMENTS

Amendments to the Partnership Agreement may be proposed by the General
Partner or by at least 10% in interest of the Limited Partners. Proposed
amendments (other than those described below) must be approved by a
Majority-In- Interest of each class of Unitholders. Unless approved by the
General Partner and by the Limited Partners holding at least 90% of each class
of Units, no amendment to Partnership Agreement will be effective unless the
Partnership has received an opinion of counsel acceptable to the General
Partner that such amendment would not result in the loss of limited liability
to any Limited Partner or cause the Partnership to be treated as an association
taxable as a corporation for federal income tax purposes.

Amendments to the Operating Partnership Agreements (other than those
described below) require the consent of the Partnership, as the limited partner
of the Operating Partnerships. No amendment to the Operating Partnership
Agreements will be effective without the consent of both partners of the
Operating Partnerships unless the Partnership has received an opinion of
counsel acceptable to the General Partner that such amendment would not result
in the loss of limited liability of the Partnership, as the limited partner of
the Operating Partnerships, or the Limited Partners, or cause the Operating
Partnerships to be treated as an association taxable as a corporation for
federal income tax purposes.

The consent of the General Partner is required if the effect of any
amendment to the Partnership Agreement or the Operating Partnership Agreements
would be to increase the duties or liabilities of the General Partner or to
change the percentage interest of the General Partner, or with respect to the
Partnership, if the Partnership has received an opinion of counsel that such
amendment would have materially adverse consequences to the General Partner.

The General Partner generally may make amendments to the Partnership
Agreement and the Operating Partnership Agreements, as applicable, without the
consent of the Limited Partners if such amendments are (i) to conform

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the provisions of such partnership agreements to any amendments to the Delaware
Act; (ii) of an inconsequential nature and do not adversely affect such Limited
Partners in any material respect; (iii) necessary or desirable to satisfy any
requirement, condition or guideline contained in any opinion, directive, ruling
or regulation of any federal or state agency or contained in any federal or
state statute; (iv) necessary or desirable to implement certain tax-related
provisions of the Partnership and the Operating Partnership Agreements; (v)
necessary or desirable to facilitate the trading of the Units or to comply with
any rule, regulation, guideline or requirement of any securities exchange on
which the Units are or will be listed for trading; (vi) necessary or desirable
in connection with the issuance of a separate class of securities as discussed
in "Description of the Partnership Agreements--Additional Classes or Series of
Units; Sales of Other Securities" above; (vii) to reflect a change in the name
of the Partnership or its principal place of business; (viii) to reflect the
admission, substitution or withdrawal of partners and initial contributions,
reductions and increases in the contributions of partners; (ix) to reflect
changes necessary to qualify the Partnership and the Operating Partnerships to
do business in other jurisdictions as limited partnerships; (x) required or
contemplated by the Partnership Agreement or the Operating Partnership
Agreements; (xi) to reflect a change in applicable federal laws and regulations
of the definition of a person qualified to hold an interest in oil and gas
leases on federal lands; (xii) to reflect a change in any provisions of the
Partnership Agreement or the Operating Partnership Agreements that requires any
action to be taken by or on behalf of the General Partner or the Partnership or
Operating Partnerships pursuant to the requirements of Delaware law if the
provisions of Delaware law are changed so that the taking of such action is no
longer required; (xiii) necessary to prevent the Partnership, the Operating
Partnerships or the General Partner or its respective directors, officers,
employees or agents from being subjected to the provisions of the Investment
Company Act of 1940, as amended, or the Investment Advisors Act of 1974, as
amended; or (xiv) similar to any of the foregoing types of amendments.

The provision of the Partnership Agreement requiring that two-thirds
in interest of the Limited Partners approve the removal of the General Partner
may not be amended without the approval of two-thirds in interest of the
Limited Partners.

MEETINGS; VOTING

The General Partner does not anticipate that any meeting of Limited
Partners will be called except under extraordinary circumstances. Any action
that is required or permitted to be taken by the Limited Partners may be taken
either at a meeting of the Limited Partners or without a meeting if consents in
writing setting forth the action so taken are signed by Limited Partners owning
not less than the minimum percentage interests that would be necessary to
authorize or take such action at a meeting at which all of the Limited Partners
were present and voted. Meetings of the Limited Partners may be called by the
General Partner or by at least 10% in interest of the Limited Partners. The
General Partner will send notice of any meeting to the Limited Partners.
Limited Partners may vote either in person or by proxy at meetings. A
Majority-In-Interest represented in person or by proxy will constitute a quorum
at a meeting of Limited Partners. Except for the special amendments referred
to above under "--Amendment of Partnership Agreement and Operating Partnership
Agreements," the removal of the General Partner and any amendment of the
percentage vote required to remove the General Partner, and except as otherwise
required by law, substantially all matters submitted to the Limited Partners
for determination will be determined by the affirmative vote, in person or by
proxy, of a Majority-In- Interest of each class of Unitholders. The holders of
each class of Units each have the right to vote separately, as a class, on all
issues presented to the Limited Partners. Actions not required to be approved
by a Majority-In-Interest or higher percentage of interest may be taken by a
majority of interests present or represented by proxy and entitled to vote at a
meeting at which a quorum is present. Each owner of a Unit has a vote equal to
his percentage interest as a Limited Partner in the Partnership. See
"Conflicts of Interest." Hallwood Group holds all Class B Units and,
therefore, any action requiring approval by a percentage of the Limited
Partners will require approval by Hallwood Group.

INDEMNIFICATION

The Partnership Agreement and the Operating Partnership Agreements
provide that the Partnership and the Operating Partnerships, respectively, will
indemnify the General Partner, its affiliates and their directors, officers,
employees and agents against any and all losses, claims, damages, liabilities,
joint and several, expenses (including reasonable legal fees and expenses),
judgments, fines, settlements and other amounts arising from any and all
claims, costs, demands, actions, suits or proceedings, civil, criminal,
administrative or investigative, in which the General Partner or such other
persons may be involved or threatened to be involved, if (i) in the case of
civil actions the General Partner or such persons acted in good faith and in a
manner it reasonably believed to be in, or not opposed to, the best interests

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of the Partnership and the Operating Partnerships and the General Partner's or
such other person's conduct did not constitute gross negligence or willful or
wanton misconduct and in the case of criminal actions the General Partner or
such other person had no reasonable cause to believe the conduct was unlawful
or (ii) the General Partner or such other person has been successful in
defending any such action or proceeding. The Partnership and the Operating
Partnerships are authorized to purchase insurance against liabilities asserted
against and expenses incurred by such persons in connection with the
Partnership's and the Operating Partnerships' activities, whether or not the
Partnership and the Operating Partnerships would have the power to indemnify
the person against such liabilities under the provisions described above. The
General Partner, its affiliates and directors will not be liable for monetary
damages to the Partnership, the limited partners or assignees for errors of
judgment or for any acts or omissions of the General Partner and such other
persons who acted in good faith. If the Partnership were to make any payments
to the General Partner or other persons under this provision, the assets of the
Partnership available for distribution to Class C Unitholders could be reduced.

Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers or persons controlling
the registrant pursuant to the foregoing provisions, the registrant has been
informed that in the opinion of the SEC such indemnification is against public
policy as expressed in such Act and is therefore unenforceable.

LIMITED LIABILITY

The Partnership Agreement provides that no Limited Partner shall be
personally liable for the debts of the Partnership in excess of his
contribution. Furthermore, under the Delaware Act, a limited partner, as such,
will not be liable for the obligations of a limited partnership in excess of
his contribution and his share of assets and undistributed profits unless he is
also a general partner or he takes part in the control of the business of the
partnership. Under the Delaware Act, a limited partner is otherwise entitled
to limited liability and is not responsible for the limited partnership's
obligations if the limited partner's activities in connection with the business
of the limited partnership are limited to the exercise by the limited partners,
in accordance with the provisions of the Partnership Agreement, of the rights
granted to the limited partners therein. However, because the limited
partnership statutes of certain other states in which the Partnership may do
business do not expressly allow Limited Partners to act in certain capacities
or expressly grant or deny certain voting rights and other powers that may be
exercised by Limited Partners in the Partnership, under the laws of such
states, the existence of such rights and powers in the Partnership Agreement
may cause Limited Partners, with respect to the operation of the Partnership's
business in such states, to be deemed to have taken part in the control of the
Partnership's business. This would subject all or some of the Limited Partners
to a risk of liability with the General Partner in excess of their respective
contributions to the Partnership and their share of assets and undistributed
profits for any civil judgment that could not be satisfied by the Partnership's
assets.

Moreover, the Delaware Act provides that the Partnership shall not
make any distribution to any Limited Partner to the extent that, at the time of
the distribution and after giving effect to the distribution, all liabilities
of the Partnership, other than liabilities to the General Partner and the
Limited Partners on account of their Partnership interests and liabilities for
which the recourse of creditors is limited to specified property of the
Partnership, exceed the fair value of the Partnership's assets, except that the
fair value of property that is subject to a liability for which the recourse of
creditors is limited shall be included in the assets of the Partnership only to
the extent that the fair value of that property exceeds that liability (the
"Prohibition"). A Limited Partner who receives a distribution in violation of
the Prohibition or if the distribution otherwise violates the Partnership
Agreement or other provisions of applicable law or the Partnership Agreement,
and who knows at the time of the distribution that the distribution violates
the Prohibition, the Partnership Agreement or other provisions of applicable
law, will be liable to the Partnership for the amount of the distribution. A
Limited Partner who receives a distribution in violation of the Prohibition,
the Partnership Agreement or other applicable law and who does not know at the
time of the distribution that the distribution violates the Prohibition, the
Partnership Agreement or other applicable law shall not be liable under the
Delaware Act for the amount of the distribution. Under the Delaware Act,
unless otherwise agreed, a Limited Partner who receives a distribution from the
Partnership has no liability under the Delaware Act or other applicable law for
the amount of the distribution after the expiration of three years from the
date of the distribution.

At such time as a person (who is not also a General Partner and who
does not take part in the control of the business of the Partnership) is
admitted or substituted as a Limited Partner in the Partnership, such person
possessing or exercising the voting rights and other powers or having acted in
the capacities set forth in the Partnership Agreement

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will not be legally obligated under the Delaware Act for the liabilities of the
Partnership in an amount in excess of his contribution or his share of assets
and undistributed profits (or in the case of a Substituted Limited Partner,
such contribution of his predecessor-in-interest) to the Partnership. Neither
the possession nor the exercise of such voting rights or other powers of
Limited Partners constitutes participation in the control of the business of
the Partnership.

BOOKS AND REPORTS

The General Partner is required to keep complete and accurate books of
the Partnership's and the Operating Partnerships' respective businesses at the
principal offices of each respective partnership. The books of the Partnership
and the Operating Partnerships will be maintained for financial reporting
purposes on an accrual basis or a cash basis, as the General Partner may, in
its sole discretion, decide and shall be adjusted periodically to an accrual
basis for reporting in accordance with generally accepted accounting
principles. The fiscal year of the Partnership and the Operating Partnerships
is the calendar year. Limited Partners will have the right to inspect and copy
any of the Partnership's books for a proper purpose related to a Limited
Partner's interest in the Partnership, but any such inspection and copying
shall be at the Limited Partner's expense.

The General Partner will furnish each Unitholder of record as of the
last day of the fiscal year, within 120 days after the close of each fiscal
year, an annual report containing financial statements of the Partnership for
the past fiscal year, presented in accordance with generally accepted
accounting principles, including a balance sheet and statements of income,
partners' equity and changes in cash flows. The financial statements will be
audited by a firm of independent public accountants selected by the General
Partner. Within 60 days after the close of each calendar quarter (except the
fourth quarter), the General Partner will furnish each Unitholder of record as
of the last day of such calendar quarter with a quarterly report containing
such financial and other information as the General Partner deems appropriate.

The General Partner will use its best efforts to furnish each
Unitholder within 75 days, and shall furnish within 90 days, after the close of
each taxable year, information reasonably required for federal and state income
tax purposes. Such information will be furnished in a summary form so that
certain complex calculations normally required of partners can be avoided. The
General Partner's ability to furnish such summary information to Unitholders
will depend on the cooperation of brokers in supplying certain information to
the General Partner.

TERMINATION, DISSOLUTION AND LIQUIDATION

The Partnership and the Operating Partnerships will continue until
December 31, 2035, unless sooner dissolved or terminated. The Partnership and
the Operating Partnerships can be dissolved upon (i) the withdrawal of the
General Partner or any other event that results in its ceasing to be the
General Partner (other than by reason of a permitted transfer of its general
partner's interest or a withdrawal occurring after, or a removal effective upon
or after, selection of a successor by a Majority-In-Interest), (ii) the
bankruptcy of the General Partner, (iii) the filing of a certificate of
dissolution or the revocation of the certificate of incorporation of the
General Partner, (iv) an election to dissolve by the General Partner that is
approved by a vote or consent of a Majority-In-Interest or (v) a written
determination by the General Partner that projected future revenues of the
Partnership will be insufficient to enable payment of projected Partnership
costs and expenses or, if sufficient, will be such that continued operation is
not in the best interests of the Partners. In the event of dissolution caused
by (i), (ii) or (iii) above, a Majority- In-Interest may elect to reconstitute
the business of the Partnership by forming a new limited partnership on the
same terms as are set forth in the Partnership Agreement. Any such election
must also provide for the election of a general partner to the reconstituted
partnership. If such an election is made, all of the Limited Partners will
continue as limited partners of the reconstituted partnership, although Limited
Partners not consenting to the continuation are entitled to withdraw on the
terms set forth in the Partnership Agreement. No such election may be made
unless prior thereto the Partnership has received an opinion of counsel
acceptable to the General Partner that (i) the election may be made without the
concurrence of all partners, (ii) the limited partners in the reconstituted
Partnership will have the same limited liability as the Limited Partners in the
Partnership, and (iii) neither the Partnership nor the reconstituted limited
partnership would be treated as an association taxable as a corporation for
federal income tax purposes upon the exercise of such right to continue. Upon
dissolution, unless an election to continue the business of the Partnership is
made, the General Partner or other person authorized to wind up the affairs of
the Partnership will proceed to liquidate the Partnership's assets and apply
the proceeds of liquidation in the order of priority set forth in the
Partnership Agreement, which permits distributions of assets in kind

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if, in the opinion of the person authorized to wind up the affairs of the
Partnership, the immediate sale of all or any part of the Partnership's assets
would be impracticable or would cause undue loss to the Partners.

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UNITS ELIGIBLE FOR FUTURE SALE

The Class C Units sold in the Offering will generally be freely
transferable without restriction or further registration under the Securities
Act, except that any Class C Units owned by an "affiliate" of the Partnership
(as that term is defined in the rules and regulations under the Securities Act)
may not be resold publicly except in compliance with the registration
requirements of the Securities Act or pursuant to an exemption therefrom under
Rule 144 thereunder ("Rule 144") or otherwise. Rule 144 permits securities
acquired by an affiliate of the issuer in an offering to be sold into the
market in an amount that does not exceed, during any three-month period, the
greater of (i) 1% of the total number of such securities outstanding or (ii)
the average weekly reported trading volume of the Class C Units for the four
calendar weeks prior to such sale. Sales under Rule 144 are also subject to
certain manner of sale provisions, notice requirements and the availability of
current public information about the Partnership. A person who is not deemed
to have been an affiliate of the Partnership at any time during the three
months preceding a sale, and who has beneficially owned his Class C Units for
at least two years, would be entitled to sell such Class C Units under Rule 144
without regard to the public information requirements, volume limitations,
manner of sale provisions or notice requirements of Rule 144.

The Partnership may issue without a vote of the Unitholders up to a
total of 100,000,000 Units of all classes. See "Description of The Partnership
Agreements--Additional Classes or Series of Units; Sales of Other Securities."

The Partnership, the Operating Partnership and the General Partner
have agreed not to (i) offer, sell, contract to sell or otherwise dispose of or
announce the offering of any Class C Units or any securities that are
convertible into, or exercisable or exchangeable for, Class C Units or any
securities that are senior to or pari passu with Class C Units or (ii) grant
any options or warrants to purchase Class C Units for a period of 180 days
after the date of this Prospectus without the prior written consent of
Principal Financial Securities, Inc.

MATERIAL FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of the material federal income
tax considerations associated with the Offering. It is based upon the Code,
the Regulations, published revenue rulings and procedures of the IRS and
judicial decisions, all as in effect on the date of this Prospectus. Any of
such authorities could be changed at any time and any such changes could
significantly modify this discussion. There is no assurance that additional
legislative, judicial, or administrative changes will not occur in the future.
Additionally, no rulings have been requested from the IRS concerning any
matters discussed herein.

The discussion below is directed primarily to the typical unitholder
acquiring Class C Units who is an individual and a United States Citizen
(except as otherwise provided herein, the term Unitholder will include holders
of any Units in the Partnership). Various additional complexities or
considerations are applicable to a Unitholder who is a partnership,
corporation, trust, estate, tax-exempt entity, or foreign person or who may be
subject to certain facts and circumstances that are applicable only to such
person and that may give rise to additional considerations. The following
discussion generally does not address any of those additional considerations.
In addition, the Offering may have state and local tax consequences to a
particular Unitholder that are not discussed below. Accordingly, each
Unitholder is urged to consult his tax advisor prior to participating in the
Offering with specific reference to the effect of his particular facts and
circumstances on the matters discussed herein.

The federal income tax consequences of the Offering and the federal
income tax treatment of Class C Unitholders depend in some instances on
determinations of fact and interpretations of complex provisions of federal
income tax laws for which no clear precedent or authority may be available.
HEPGP, in determining the Partnership's taxable income, allocations, basis
adjustments and asset valuations, must make determinations in its capacity as
general partner of the Partnership that could affect the Class C Unitholders.
Where appropriate, HEPGP will act upon the advice of legal counsel or other
professional tax advisors in making such interpretations and determinations.

OPINION OF COUNSEL

Except as expressly provided below, the following discussion
represents the opinion of Jenkens & Gilchrist, a Professional Corporation,
counsel to the Partnership ("Counsel"), of the material federal income tax
considerations that are associated with the Offering and that are applicable to
a Class C Unitholder that is an individual and a United

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States citizen. The opinions of Counsel are based on factual representations
and assumptions and subject to the qualifications set forth in the discussion
that follows. In addition, such opinions are based upon existing provisions of
the Code and the Regulations, existing rulings and procedures of the IRS and
existing court decisions and there can be no assurances that any of such
authorities will not be changed in the future. The opinions set forth herein
represent only Counsel's best legal judgment as to the particular issues and
are not binding on the IRS or the courts. No ruling from the IRS has been
requested or received with respect to any issues discussed herein and no
assurance can be provided that the opinions and statements set forth herein
would be sustained by a court if challenged by the IRS.

TAX SHELTER NOT A SIGNIFICANT OR INTENDED BENEFIT OF INVESTMENT IN THE
PARTNERSHIP

A person who acquires a Class C Unit in the Partnership pursuant to
the Offering is advised that tax shelter of income unrelated to the Partnership
is not a significant or intended feature of an investment in the Partnership.
HEPGP does not expect that a Unitholder acquiring Class C Units in the
Partnership will realize any significant tax shelter from an investment in the
Class C Units.

TAX CLASSIFICATION OF THE PARTNERSHIP

The applicability of the federal income tax consequences described
herein depends on the treatment of the Partnership, EDPO and HEPO as
partnerships for federal income tax purposes and not as associations taxable as
corporations. In the event the Partnership, HEPO or EDPO should be taxed as a
corporation rather than as a partnership, the effect thereof would
substantially reduce the after-tax economic return of an investment in the
Partnership. For federal income tax purposes, a partnership is not a taxable
entity but rather a conduit through which all items of partnership income,
gain, loss, deduction and credit are passed to its partners. Thus, income and
deductions resulting from partnership operations are allocated to the partners
and are taken into account by the partners on their individual federal income
tax returns. In addition, a distribution of money from a partnership to a
partner generally is not taxable to the partner unless the amount of the
distribution exceeds the partner's tax basis in his interest in the
partnership. If an organization formed as a partnership were classified for
federal income tax purposes as an association taxable as a corporation, the
organization would be a separate taxable entity. In such a case, the
organization, rather than its members, would be taxed on the income and gains
and would be entitled to claim the losses and deductions resulting from its
operations. A distribution from the organization to a member would be taxable
to the member in the same manner as a distribution from a corporation to a
shareholder (i.e., as ordinary income to the extent of the current and
accumulated earnings and profits of the organization, then as a nontaxable
reduction of basis to the extent of the member's tax basis in his interest in
the organization and finally as gain from the sale or exchange of the member's
interest in the organization).

An entity generally will be classified as a partnership rather than as
a corporation for federal income tax purposes if the entity (i) is treated as a
partnership under Treasury Regulations, effective January 1, 1997, relating to
entity classification (the "Check-the-Box Regulations") and (ii) is not a
"publicly traded partnership" taxed as a corporation under Section 7704 of the
Code. In general, under the Check-the-Box Regulations, an unincorporated
domestic entity with at least two members may elect to be classified either as
an association taxable as a corporation or as a partnership. If such an entity
fails to make any election, it will be treated as a partnership for federal
income tax purposes. Special rules apply to entities, such as the Partnership,
HEPO, and EDPO, in existence on January 1, 1997. The federal income tax
classification of an entity that was in existence prior to January 1, 1997 will
be respected for all periods prior to January 1, 1997 if (i) the entity had a
reasonable basis for its claimed classification, (ii) the entity and all
members of the entity recognized the federal tax consequences of any changes in
the entity's classification within the 60 months prior to January 1, 1997, and
(iii) neither the entity nor any of its members were notified in writing on or
before May 8, 1996 that the classification of the entity was under examination.
For periods after January 1, 1997, an entity that was in existence prior to
January 1, 1997 will have the same classification (e.g., partnership or
corporation) that the entity claimed for the prior period unless it elects
otherwise.

To be taxed as a partnership for federal income tax purposes, the
Partnership, in addition to qualifying as a partnership under the Check-the-Box
Regulations, must not be taxed as a corporation under Section 7704 of the Code
dealing with publicly traded partnerships. The Partnership (but not HEPO or
EDPO) constitutes a "publicly traded partnership" within the meaning of Section
7704 of the Code. Section 7704 of the Code taxes certain publicly traded
partnerships as corporations. However, an exception exists with respect to
publicly traded partnerships of which 90

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percent or more of gross income for each taxable year consists of "qualifying
income." For this purpose, qualifying income includes income and gains derived
from the exploration, development, production, processing, refining,
transportation (including pipelines) or marketing of oil and gas and gains from
the sale or disposition of assets used in such activities ("Qualifying
Income"). The Partnership has represented that, other than interest income
derived from short-term investments, the Partnership's only source of income is
its distributive share of the Operating Partnerships' income. Each Operating
Partnership has represented that in excess of 90% of its gross income will be
Qualifying Income for purposes of Section 7704 of the Code. Based upon these
representations, at least 90% of the Partnership's gross income will constitute
Qualifying Income.

If (a) a publicly traded partnership fails to meet such gross income
test for any taxable year, (b) such failure is inadvertent, as determined by
the IRS and (c) the partnership takes steps within a reasonable time to once
again meet the gross income test and agrees to make such adjustments and pay
such amounts (including the amount of tax liability that would be imposed on
the partnership if it were treated as a corporation during the period of
inadvertent failure) as are required by the IRS, such failure will not cause
the partnership to be taxed as a corporation. If the Partnership fails to meet
the gross income test with respect to any taxable year, HEPGP, as general
partner of the Partnership, will use its best efforts to assure that the
Partnership will qualify under the inadvertent failure exception discussed
above. The provision taxing certain publicly traded partnerships as
corporations (Section 7704 of the Code) generally is not applicable to
"existing partnerships" (i.e., generally, partnerships that were publicly
traded partnerships on December 17, 1987) until January 1, 1998. However, a
partnership will no longer qualify as an "existing partnership" if its adds a
"substantial new line of business" (a "Substantial New Line of Business"). For
this purpose, (i) a new line of business is any business activity of the
partnership not closely related to a pre-existing business to the extent that
such activity generates income other than Qualifying Income; and (ii) such new
line of business will be treated as substantial as of the earlier of (a) the
taxable year in which the partnership derives more than 15% of its gross income
from that line of business; or (b) the taxable year in which the partnership
directly uses in that line of business more than 15% (by value) of its total
assets. For this purpose, the Partnership should be considered to be an
"existing partnership." Thus, the provisions of Section 7704 of the Code will
become applicable to the Partnership for taxable years beginning after December
31, 1997.

Counsel has opined that the Partnership, HEPO and EDPO each will be
classified as a partnership for federal income tax purposes and will not be
classified as an association taxable as a corporation. Such conclusion is
based in part upon the accuracy of the following representations made by HEPGP
and the Partnership:

a. That the Partnership, HEPO and EDPO will be operated in
accordance with (a) all applicable partnership statutes, (b) the Partnership
Agreement and (c) this Prospectus.

b. That the Units of each of Hallwood Energy Partners, L.P., a
Delaware limited partnership, and Energy Development Partners, a Colorado
limited partnership ("EDP") as such entities existed in 1990, were traded on
the American Stock Exchange prior to their merger on December 17, 1987.

c. That, from December 17, 1987 through December 31, 1997, each
of Hallwood Energy Partners, L.P., a Delaware limited partnership, and EDP (as
such entities existed prior to their merger in 1990, and the Partnership for
all times thereafter, did not and will not add any Substantial New Line of
Business.

d. That for each taxable year beginning after December 31, 1997,
less than 10 percent of the gross income of the Partnership will be derived
from sources other than Qualifying Income.

e. That neither the Partnership, nor HEPO and EDPO was notified
in writing on or before May 8, 1996 that its classification was under
examination.

f. That neither the Partnership, HEPO nor EDPO will make an
election under the Check-the-Box Regulations to treat itself as an association
taxable as a corporation.

The following discussion assumes that the Partnership, HEPO and EDPO
each is, and will continue to be, treated as a partnership for federal income
tax purposes.

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TAX CONSEQUENCES OF THE OFFERING

General. Section 721(a) of the Code provides that, in general, no
gain or loss is recognized by a partnership or by any of its partners upon a
contribution of property to the partnership in exchange for an interest in the
partnership. Pursuant to the Offering, the Partnership will issue Class C
Units to each person who contributes cash to the Partnership. Section 721 (a)
of the Code will apply to the transfers of cash to the Partnership in exchange
for the Class C Units issued pursuant to the Offering.

Tax Consequences to the Partnership. Under Section 721(a) of the
Code, the Partnership will recognize no gain or loss upon its receipt of cash
pursuant to the Offering.

GENERAL FEATURES OF PARTNERSHIP TAXATION

Status as Partners. A person who (a) acquires beneficial ownership of
Class C Units pursuant to the Offering and who has executed a Transfer
Application and either has been admitted or is awaiting admission to the
Partnership as a limited partner or (b) acquires beneficial ownership of Class
C Units pursuant to the Offering and whose Class C Units are held by a nominee
(so long as such person has the right to direct the nominee in the exercise of
all substantive rights attendant to the ownership of such Class C Units) will
be treated as a partner of the Partnership for federal income tax purposes.
However, a person who is entitled to execute and deliver a Transfer Application
but who fails to do so or whose Class C Units are held by a nominee where such
person does not have the right to direct the nominee in the exercise of all
substantive rights attendant to the ownership of such Class C Units may not be
treated as a partner of the Partnership for federal income tax purposes. If a
Class C Unitholder is not treated as a partner for federal income tax purposes,
he would not be taxed in accordance with the principles discussed herein. In
addition, such person would not be allocated any item of Partnership income,
gain, loss or deduction and any cash distributions from the Partnership
received by such person would likely be taxed as ordinary income.

A Unitholder whose Units are loaned to a "short seller" to cover a
short sale of the Units may be considered as having disposed of ownership of
those Units. In such a case, such Unitholder would no longer be a partner for
federal income tax purposes with respect to such Units during the period of the
loan and may recognize gain or loss from the disposition. During such period,
items of Partnership income, gain, loss or deduction would not be allocable to
such Unitholder and any cash distributions from the Partnership received by
such Unitholder with respect to such Units would appear to be fully taxable as
ordinary income. The IRS may also contend that a loan of Units to a "short
seller" constitutes a taxable exchange. Counsel is unable to opine regarding
the status of a Unitholder as a partner in the Partnership during the period of
the loan to a "short seller." Unitholders desiring to assure their status as
partners and avoid the risk of gain recognition should modify any applicable
brokerage account agreements to prohibit their brokers from borrowing their
Units.

The Taxpayer Relief Act of 1997 (the "TRA of 1997") also contains
provisions affecting the taxation of certain financial products and securities,
including partnership interests, by treating a taxpayer as having sold an
"appreciated" partnership interest (one in which gain would be recognized if it
were sold, assigned or otherwise terminated at its fair market value) if the
taxpayer or related persons enter into a short sale of, an offsetting notional
principal contract with respect to or a futures or forward contract to deliver
the same or substantially identical property, or in the case of an appreciated
financial position that is a short sale or offsetting notional principal
contract or futures or forward contract, the taxpayer or related persons
acquire, the same or substantially identical property. The Secretary of the
Treasury is also authorized to issue regulations that treat a taxpayer that
enters into transactions or positions that have substantially the same effect
as the preceding transactions as having constructively sold the financial
position.

The discussion below is applicable only to, and references to
Unitholders in connection with federal income tax matters refer only to,
persons who are considered to be partners of the Partnership for federal income
tax purposes.

Taxation of Partners. For each taxable year, each Unitholder is
required to take into account on his individual federal income tax return his
distributive share of the Partnership's income, gains, losses and deductions
for such taxable year. Each Unitholder is required to take such distributive
share into account in computing his federal income tax liability regardless of
whether he has received or will receive any cash distributions from the
Partnership. Therefore, he may be required to report and pay tax on income
that the Partnership recognizes during the taxable year without

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receiving any cash distribution from the Partnership. In addition, because
cash distributions will be made only to those persons who are Unitholders of
record on a specified date during each quarter, while the Partnership's income,
gains, losses and deductions are allocated for federal income tax purposes to
persons who are record holders of Units on the last day of the month preceding
the month in which the income, gains, losses and deductions accrue, income may
be allocated to Unitholders who receive no cash distributions in respect of
that income.

A distribution of cash to a Unitholder generally is not taxable to
such Unitholder unless the amount of such distribution exceeds the Unitholder's
basis in his Units. Distributions are not expected to exceed a Class C
Unitholder's basis in his Class C Units. If an excess distribution occurred,
however, such excess should be taxable as capital gain, assuming the Units in
respect of which the distribution was made are held as a capital asset. If,
however, any portion of such distribution is considered to be in exchange for
the Unitholder's interest in ordinary income items (including potential
recapture of depletion or intangible drilling and development costs), such
portion will be taxed as ordinary income even if the amount of the distribution
did not exceed the Unitholder's tax basis in his Units. In addition, a
Unitholder could recognize income if cash distributions made to him cause his
at-risk amount to be reduced below zero. See "Material Federal Income Tax
Considerations General Features of Partnership Taxation--Limitations on
Deduction of Losses--At-Risk Limitation."

If the Partnership, HEPO or EDPO have any nonrecourse liabilities
(i.e., liabilities for which no partner, including the general partner, is
personally liable) outstanding at any time, each Unitholder, for purposes of
computing his tax basis in his Units, will be allocated a share of such
nonrecourse liabilities (generally based on his proportionate interest in the
Partnership's profits). See "Federal Income Tax Considerations--General
Features of Partnership Taxation--Computation of Basis" below. Any subsequent
decrease in a Unitholder's share of such nonrecourse liabilities will be
treated as a distribution of cash to the Unitholder. A decrease in a
Unitholder's proportionate share of the Partnership's profits resulting from an
issuance of additional Units by the Partnership will result in such a decrease
in such Unitholder's share of nonrecourse liabilities and, thus, a deemed
distribution to such Unitholder. Such deemed distribution may result in
ordinary income to the Unitholder to the extent that he is considered to have
exchanged for the deemed distribution a portion of his interest in the
Partnership's ordinary income items (including potential recapture of depletion
or intangible drilling and development costs). The Partnership, HEPO and EDPO
have not incurred, and HEPGP does not currently intend to incur nonrecourse
debt.

Computation of Basis. A Unitholder who acquires Class C Units
pursuant to the Offering generally will have an initial tax basis in such Class
C Units equal to the amount of the Unitholder's contribution of money to the
Partnership and the Unitholder's share of the Partnership's nonrecourse
liabilities, if any. That initial tax basis will be increased by the
Unitholder's share of the Partnership's income and gains (including gain on the
sale of an oil or gas property by the Partnership, as separately computed by
the Unitholder) and his share of Partnership nonrecourse liabilities, if any.
The tax basis will be decreased (but not below zero) by the Unitholder's share
of the Partnership's losses and deductions (including loss on the sale of an
oil or gas property by the Partnership, as separately computed by the
Unitholder), the amount of any distributions from the Partnership received by
him (including any decrease in his share of Partnership nonrecourse
liabilities, if any) and the amount of his depletion deductions with respect to
the Partnership's properties (to the extent that such depletion deductions do
not exceed his allocable share of the tax basis of such property). It should
be noted that a Unitholder's tax basis in his Units will be decreased by his
share of the Partnership's losses even though those losses may not be currently
deductible by him because of the at-risk or passive loss limitations.

Limitations on Deduction of Losses. The General Partner does not
anticipate that holders of Class C Units will be allocated losses and
deductions of the Partnership in excess of their allocable share of the income
and gain of the Partnership. However, the ability of a Unitholder to deduct
his share of the Partnership's net tax losses or deductions (if any) during any
particular year is subject to the basis limitation, the at-risk limitation, the
passive loss limitation and the limitation on the deduction of investment
interest.

(a) Basis Limitation. A Unitholder may not deduct from his
taxable income any amount attributable to his share of the Partnership's losses
or deductions that is in excess of the tax basis of his Units at the end of the
Partnership's taxable year in which the losses or deductions occur. For a
discussion of the computation of a Unitholder's tax basis in his Units, see
"Material Federal Income Tax Considerations--General Features of Partnership
Taxation--Computation of Basis" above. Any losses or deductions that are
disallowed by reason of the basis limitation may be carried forward

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and deducted in later taxable years to the extent that the Unitholder's tax
basis in his Units is increased in such later years (subject to application of
the other limitations discussed below).

(b) At-Risk Limitation. A Unitholder (other than corporations
that are neither S corporations nor certain closely-held corporations) may not
deduct from his taxable income any amount attributable to his share of the
Partnership's losses or deductions that is in excess of the amount for which he
is considered to be at-risk with respect to the Partnership's activities at the
end of the Partnership's taxable year in which the losses or deductions occur.
A Unitholder who acquires his Class C Units pursuant to the Offering generally
will have an initial at-risk amount with respect to the Partnership's
activities equal to the amount of cash contributed to the Partnership in
exchange for his Class C Units, assuming such Class C Unitholder uses his
personal funds to make such contribution or borrows the funds on a recourse
basis from a lender unrelated to the Partnership. This initial at-risk amount
will be increased by the Partner's share of the Partnership's income and gains
and the amount by which the Partner's deductions for percentage depletion with
respect to an oil or gas property owned by the Partnership exceed the Partner's
allocable share of the tax basis of the property, and will be decreased by
their share of the Partnership's losses and deductions and the amount of cash
distributions made to the Partner. Liabilities of the Partnership, whether
recourse or nonrecourse, generally will not increase a Class C Unitholder's
amount at-risk with respect to the Partnership.

Any losses or deductions that may not be deducted by reason of the
at-risk limitation may be carried forward and deducted in later taxable years
to the extent that the Class C Unitholder's at-risk amount is increased in such
later years (subject to application of the other limitations). Upon the
taxable disposition of a Class C Unit, any gain recognized by a Class C
Unitholder generally can be offset by losses that have been suspended by the
at-risk limitation. Any excess loss (above such gain) previously suspended by
the at-risk limitation is no longer utilizable.

Generally, the at-risk limitation is to be applied on an
activity-by-activity basis and, in the case of oil and gas properties, each
property is treated as a separate activity. Thus, an investor's interest in
each oil or gas property is treated separately so that a loss from any one
property is limited to the at-risk amount for that property and not the at-risk
amounts for the investor's other oil or gas properties. It is uncertain how
this rule is implemented in the case of multiple oil and gas properties owned
by a single partnership. However, for taxable years ending on or before the
date on which further guidance is published, the IRS will permit aggregation of
all properties owned by a partnership in computing a partner's "at-risk"
limitation with respect to such partnership. Moreover, any rules that would
impose certain limitations and conditions on the ability of taxpayers to
aggregate such activities will be effective only for any taxable year ending
after the rules are issued. Thus, it is not known to what extent aggregation
will be permitted after 1996.

If the amount for which a Class C Unitholder is considered to be at
risk with respect to the activities of the Partnership is reduced below zero
(e.g., by distributions), the Class C Unitholder will be required to recognize
ordinary income to the extent that his at-risk amount is reduced below zero.
The amount of ordinary income so recognized, however, cannot exceed the excess
of the amount of the Partnership's losses and deductions previously claimed by
the Class C Unitholder over any amounts of ordinary income previously
recognized pursuant to this rule. The losses and deductions so "recaptured"
will again become available as deductions when, as and if the Class C
Unitholder's at-risk amount increases above zero.

(c) Passive Loss Limitation. Even if the deductibility of a Class
C Unitholder's share of the Partnership's losses is not limited by such Class C
Unitholder's adjusted basis or at-risk amount, such losses will be subject to
the passive loss rules if the Class C Unitholder is an individual, estate,
trust, closely held corporation or personal service corporation. Generally, a
taxpayer's passive losses are deductible only to the extent of the taxpayer's
passive income; such losses cannot be deducted against the taxpayer's salary,
portfolio income, or active business income. A Class C Unitholder's investment
in Class C Units is considered to be a passive investment, and therefore, the
losses and income attributable to such Class C Units should be considered to be
passive losses and passive income, respectively.

Generally, passive losses arising from an investment may be used to
offset passive income arising from any passive investment. Similarly, passive
income arising from an investment generally may be offset by passive losses
from any passive investment. However, the passive loss limitations are applied
separately with respect to each publicly traded partnership, such as the
Partnership. Consequently, passive losses arising from an investment in Units
must be suspended, carried forward and used to offset the passive income, if
any, that arises from such investment in Units in subsequent taxable years;
such losses may not be used to offset the income arising from any other passive
investment.

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Similarly, passive income arising from an investment in Units may be offset by
passive losses only if such losses arise from an investment in Units; to the
extent that the passive income arising from an investment in Units exceeds the
losses arising therefrom, such income may not be offset with passive losses
from other passive investments.

Because of the application of the passive loss rules to the income and
losses generated by the Partnership, an investment in Class C Units will not
give rise to losses that may be used to offset income from any source (whether
an active or passive investment) other than the Class C (or other) Units.

When a Class C Unitholder sells all his Class C (and all other) Units
in a fully taxable transaction to someone other than a related party, any
losses arising from the Partnership that have been suspended by reason of the
passive loss limitation become fully deductible. If the Class C Unitholder
sells only part of his Units, such suspended passive losses do not become fully
deductible at that time and any gain recognized on such partial sale is treated
as passive income.

The Partnership's portfolio income may not be offset by losses
generated by the Partnership. Portfolio income includes interest, dividends,
royalties and gains from the sale of assets that generate portfolio income.
Portfolio income is not treated as passive income, but instead must be
accounted for separately. Consequently, the Partnership's portfolio income
will retain its character as portfolio income in the hands of the Class C
Unitholders and will not be available to offset passive losses (either from the
Partnership or otherwise).

(d) Nonbusiness Interest Limitation. Generally, a non-corporate
taxpayer's "investment interest" may be deducted only to the extent of the
taxpayer's "net investment income." Any investment interest that is not
deductible solely by reason of this limitation may be carried forward to later
taxable years and treated as investment interest in such later years. In
general, investment interest is any interest paid or accrued on debt incurred
or continued to purchase or carry property held for investment, and net
investment income includes gross income and certain net gain from property held
for investment, reduced by expenses that are directly connected with the
production of such income and gains. Under Treasury Regulations which the IRS
has announced that it will issue, a partner's net passive income from a
publicly traded partnership (such as the Partnership) will be treated as
investment income for purposes of the investment interest limitation.

To the extent that interest is attributable to a passive activity
(which may include interest incurred or deemed to have been incurred by a Class
C Unitholder to acquire or carry his Class C Units and a Class C Unitholder's
share of interest incurred by the Partnership in connection with its
operations), it is treated as a passive activity deduction and is subject to
limitation under the passive loss limitation discussed above and not under the
investment interest limitation. In addition, the effect of the investment
interest limitation on a particular Unitholder will depend on such Unitholder's
personal tax situation. Accordingly, each Class C Unitholder should consult
with his tax advisor.

Tax Allocations. The following is a discussion of the tax allocations
of items of Partnership income, gain, loss, deduction and credit.

(a) General. As noted above, each Class C Unitholder will be
required to take into account in determining his federal income tax liability
his distributive share of each item of Partnership income, gain, loss,
deduction or credit for the taxable year of the Partnership ending with or
within his taxable year, regardless of whether such Unitholder has received or
will receive any distributions of cash or other property from the Partnership.
Under Section 704(b) of the Code, the allocations in a partnership agreement
control the tax allocation of partnership income, gains, losses, deductions and
credits, unless such allocations do not have "substantial economic effect". If
the allocations provided in a partnership agreement do not have "substantial
economic effect," a partner's distributive share will be determined in
accordance with his interest in the partnership, determined by taking into
account all facts and circumstances.

An allocation to a partner will be considered to have "economic
effect" only if the partner to whom the allocation is made will receive the
economic benefit or bear the economic burden corresponding to such allocation.
Generally, an allocation will have economic effect if under the partnership
agreement (i) the partners' capital accounts are determined and maintained
throughout the full term of the partnership in accordance with specific
accounting rules, (ii) liquidation proceeds are required to be distributed in
accordance with the partners' capital account balances and (iii) the partners
are liable to the partnership to restore any deficit in their capital accounts
upon liquidation of the partnership. If the first two of these requirements
are met but the partner to whom an allocation is made is not obligated to
restore

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the full amount of any deficit balance in his capital account, the allocation
still will be considered to have "economic effect" to the extent the allocation
does not cause or increase a deficit balance in the partner's capital account
(determined after reducing that account for certain "expected" adjustments,
allocations and distributions specified by the Treasury Regulations), but only
if the partnership agreement contains a "qualified income offset" provision. A
qualified income offset provision requires that, in the event of any unexpected
distribution or specified adjustments or allocations to a partner that causes
or increases a deficit balance in such partner's capital account, there must be
an allocation of income or gain to that partner that eliminates the resulting
capital account deficit as quickly as possible.

The economic effect of an allocation will be deemed "substantial" if
there is a reasonable possibility that the allocation will affect substantially
the dollar amounts to be received by the partners from the partnership,
independent of tax consequences. The economic effect of an allocation,
however, is not substantial if it appears at the time the allocation is
included in the partnership agreement that the inclusion of that particular
allocation may cause the after-tax economic consequences of at least one
partner to be enhanced, in present value terms, and there is a strong
likelihood that the inclusion of such allocation will not diminish
substantially the after-tax consequences of any partner, in present value
terms.

If a partnership allocation fails to meet the substantial economic
effect test, the allocation nevertheless will be valid if, taking into account
all the facts and circumstances, the allocation is in accordance with the
partners' interests in the partnership. The partners' interests in the
partnership are to be determined based on the manner in which the partners have
agreed to share the economic benefit or burden with respect to the income,
gain, loss, deduction or credit that is allocated. In making such
determination, relevant factors include the partners' relative contributions to
the partnership, their interests in economic profits and losses, cash flow and
other nonliquidating distributions and the rights to distributions of capital
and other property upon liquidation.

(b) Allocations Under the HEP Partnership Agreement. The manner
in which items of income, gain, loss and deduction of the Partnership are
allocated for federal income tax purposes is set forth in the Partnership
Agreement. See "Description of the Partnership Agreements." In general, each
item of operating income, gain, loss, deduction and credit of the Partnership
is allocated 99% to the Unitholders and 1% to HEPGP. Operating income
generally will be allocated first to the holders of Class C Units to the extent
of the operating losses and deductions allocated to such holders; second, to
the holders of the Class C Units to the extent of their aggregate preference
amount (as described below), whether or not actually distributed; and third, to
the holders of the Class A and Class B Units, pro rata in accordance with their
percentage interests. If a Class C Unitholder receives actual cash
distributions in excess of the operating income allocated to him, he will be
allocated gross income in an amount equal to such excess. Operating loss
generally will be allocated first to the holders of Class A and B Units until
their Adjusted Capital Accounts (as defined in the Agreement) are reduced to
zero; second, to the holders of Class C Units until their Adjusted Capital
Accounts are reduced to zero; and third, to the holders of Class A and B Units
pro rata in accordance with their percentage interests. All amounts to be
allocated to the Unitholders as a class (Class A, Class B or Class C, as the
case may be) will be allocated between the Unitholders in accordance with their
respective percentage interests in the Partnership. Gain from a terminating
capital transaction generally will be allocated first to the holders of the
Class C Units until their positive capital account balances are equal to their
unpaid preference amounts and then to the holders of the Class A, Class B and
Class C Units, pro rata in accordance with their percentage interests. Loss
from a terminating capital transaction generally will be allocated first to the
Unitholders until their positive capital account balances are equal to their
unpaid preference amount, then to the holders of Class C Units until their
positive capital account balances are equal to zero, and then to the holders of
the Class A and Class B, pro rata in accordance with their percentage
interests.

The Class C Units are entitled to a preferential distribution of $1.00
per Class C Unit per year, payable quarterly to holders of record on March 31,
June 30, September 30 and December 31 in each year. The Class C preferential
distribution is cumulative, and no distributions may be paid or declared on
Class A or Class B Units unless all accrued and unpaid distributions on the
Class C Units have been paid or declared and duly provided for. Operating
distributions generally will be made first to the holders of Class C Units to
the extent of their unpaid preference amounts and then to the holders of the
Class A and Class B Units, generally in accordance with their percentage
interests. Liquidation proceeds, after all payments are made to the
Partnership's creditors, will be made to the Unitholders to the extent of and
in proportion to the positive balances of their respective capital accounts.

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(c) Allocations Under the HEPO Partnership Agreement. In general,
each item of income, gain, loss, deduction and credit of HEPO is allocated 99%
to the Partnership (as the sole limited partner of HEPO) and 1% to HEPGP (as
the General Partner of HEPO). Operating distributions will be made 99% to the
Partnership and 1% to HEPGP. Liquidation proceeds, after all payments are made
to HEPO's creditors (including partners), will be made to HEPO's partners to
the extent of and in proportion to the positive balances of their respective
capital accounts. The HEPO Partnership Agreement provides for capital accounts
to be maintained for each partner in accordance with applicable principles set
forth in the Regulations. The HEPO Agreement does not require the Partnership,
as a limited partner, to restore any deficit balance in its capital account
upon the liquidation of HEPO.

(d) Allocations Under the EDPO Partnership Agreement. Except as
otherwise described below, each item of income, gain, loss, deduction and
credit of EDPO generally is allocated 1% to HEPGP (as the General Partner of
EDPO) and 99% to Partnership (as the sole limited partner of EDPO). With
respect to productive wells located on or production from which is attributable
to (i) properties acquired by EDPO on its inception in 1985 (the "Initial
Properties") and (ii) properties other than those acquired by EDPO on its
inception in 1985 (the "Other Properties") that were acquired on or after May
9, 1990, income and loss generally shall be allocated 1/99ths to HEPGP as
General Partner and 98/99ths to the Partnership. With respect to productive
wells located on or production from which is attributable to Other Properties
that were acquired before May 9, 1990, income and loss generally shall be
allocated 4/99ths to HEPGP as General Partner and 95/99ths to the Partnership.

With respect to each development well drilled that is located on or
production from which is attributable to the Initial Properties and each
development well that is located on or production from which is attributable to
the Other Properties and that is drilled after the date of acquisition by the
partnership of an interest in such well, income and loss shall be allocated as
follows: (i) the costs through completion attributable to such development well
generally will be allocated 100% to the Partnership and (ii) all other costs
and revenues attributable to such development wells will be allocated to
4/99ths to HEPGP as General Partner and 95/99ths to the Partnership.

With respect to each exploratory well drilled that is located on or
production from which is attributable to the Initial Properties and each
exploratory well that is located on or production from which is attributable to
the Other Properties and that is drilled after the date of acquisition by the
partnership of an interest in such well, (i) the costs through completion
attributable to such exploratory well generally will be allocated 1/11th to
HEPGP and 10/11ths to the Partnership, and (ii) all other costs and revenues
attributable to such exploratory well generally will be allocated 8/33rds to
the General Partner and 25/33rds to the Partnership.

With respect to each of the Other Properties acquired by the
Partnership, (i) the Initial Acquisition Costs incurred prior to or in
connection with the acquisition of Other Properties that are classified as
Undeveloped Acreage shall be allocated 1/99th to HEPGP and 98/99ths to the
Partnership and (ii) all other Initial Acquisition Costs shall be allocated to
the Partnership.

Operating distributions generally will be made to the partners of EDPO
in the same percentage interests as taxable income was allocated (see
discussion above). Liquidation proceeds, after all payments are made to EDPO's
creditors (including partners), will be distributed to EDPO's partners to the
extent of and in proportion to the positive balances of their respective
capital accounts. The EDPO Partnership Agreement provides for capital accounts
to be maintained for each partner in accordance with applicable principles set
forth in the Regulations. The EDPO Partnership Agreement provides that any
partner having a negative balance in its capital account upon liquidation will
be required to restore the amount of such deficit to EDPO.

(e) Section 704(c) Allocations. Section 704(c) of the Code
requires, in general, that items of income, gain, loss and deduction
attributable to property that is contributed to a partnership must be allocated
in such a way as to take into account the variation between a partnership's
adjusted tax basis in such property and the fair market value of such property
at the time of contribution. These same concepts apply generally in the case
of any revaluations of the assets of a partnership, including revaluations upon
the admission of a new partner, such as the Class C Unitholders.

The Treasury Regulations under Section 704(c) of the Code (the
"Section 704(c) Regulations") provide that any allocation intended to take into
account the variation between the fair market value of contributed property and
its adjusted tax basis must be made using a reasonable method that is
consistent with the purpose of Section 704(c) of the

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Code. The purpose of Section 704(c) of the Code is to ensure that when a
partner contributes property to a partnership, with such property having a
variation between its adjusted basis and fair market value at the time of
contribution, such partner receives the tax burdens and benefits of any such
built-in gain or loss. The Section 704(c) Regulations describe three
allocation methods that are generally reasonable: the "traditional method," the
"traditional method with curative allocations," and the "remedial allocation
method." While other methods are permissible; any method, including one of the
three specifically enunciated methods, must be a reasonable method under the
circumstances. The Section 704(c) Regulations address certain instances
(generally referred to as the "ceiling limitations") attributable to
contributed property that permit reasonable curative or remedial allocations to
eliminate disparities between book and tax items. The Section 704(c)
Regulations provide in general that Section 704(c) of the Code applies on a
property-by- property basis and that aggregation of built-in gains and built-in
losses on items of contributed property is not permitted. A number of
operating rules are set forth in the Section 704(c) Regulations as
prerequisites for the use of either curative or remedial allocations. The
Partnership Agreement provides that, for federal income tax purposes, items
with respect to properties contributed to the Partnership will be allocated
among the Unitholders in a manner consistent with Section 704(c) of the Code so
as to take into account the differences between the Partnership's adjusted tax
basis in each contributed property and the fair market value of such property
at the time of its contribution.

Upon a revaluation of partnership property under Treasury Regulation
Section 1.704-1(b)(2)(iv)(f), including a revaluation upon the admission of a
new partner, the Partnership may increase or decrease partners' capital
accounts by their allocable share of the difference between the book value and
fair market value ("Pre-Revaluation Appreciation or Depreciation") of the
pre-revaluation assets of the partnership on the date of the revaluation. Upon
the admission of the Class C Unitholders to the Partnership, HEPGP intends to
administer the Partnership Agreement so that Pre- Revaluation Appreciation or
Depreciation (the functional equivalent, respectively, of built-in gain or
loss) attributable to properties acquired by the Partnership prior to the
consummation of the Offering ("Pre-Offering Property") will be allocated among
all Unitholders in accordance with the principles of Section 704(c) of the Code
and the regulations thereunder.

It is uncertain whether the Partnership has made and will be able to
make allocations of income, gain, loss and deduction with respect to property
contributed to the Partnership (or revalued upon the admission of partners in
prior offerings) which are consistent with the requirements of Section 704(c)
of the Code. Such uncertainty arises from the complexities associated with the
large number of partners that have contributed property to the Partnership and
the revaluation of Partnership property upon the admission of partners, the
fact that the Units are publicly traded, and the lack of authority under the
applicable Code provisions, including the Code provisions pertaining to the
allocation of depletable basis in oil and gas properties, as discussed below.
For these same reasons, it is uncertain whether the Partnership has made and
will be able to make allocations of income, gains, losses and deductions with
respect to Pre- Offering Property which are consistent with the principles of
Section 704(c) of the Code. See "Depletable Basis," below. Also, unless the
allocations are consistent with the Section 704(c) Regulations for Pre-Offering
Property, it is uncertain whether the Partnership's allocations will be
sustained under Section 704(b) of the Code.

As a result of the uncertainty expressed above, Counsel is unable to
express an opinion regarding whether the allocation of income, gain, loss and
depreciation or depletion deductions among the Unitholders with respect to the
contributed property and the revalued Pre-Offering Property are consistent with
the requirements of Section 704(c) of the Code and, therefore, whether the
allocations will be sustained if challenged by the IRS. If the Partnership's
allocations under Section 704(c) of the Code were successfully challenged by
the IRS, tax items of Partnership income, gain, loss and deduction would be
reallocated among the Unitholders and the Unitholders' respective tax
liabilities would be adjusted, with the result that some Unitholders may be
required to pay additional tax.

(f) Depletable Basis. Section 613A(c)(7)(D) of the Code and the
regulations thereunder (the "Section 613A Regulations") provide that a
partnership's basis in each depletable property it acquires shall be allocated
as of the date of acquisition among its partners and that each partner shall
use their proportionate share of such basis in computing their depletion with
respect to such property and their gain or loss on the disposition of such
property by the partnership. The Section 613A Regulations provide that the
basis of oil and gas property owned by a partnership is allocated among the
partners in accordance with their proportionate interest in partnership capital
unless the partnership agreement provides for an allocation of such basis in
accordance with their proportionate interest in partnership income and, at the
time of such allocation, the share of each partner in partnership income is
reasonably expected to be substantially unchanged throughout the life of the
partnership. Generally, a partner's interest in partnership capital or income
is

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determined by taking into account all facts and circumstances relating to the
economic arrangement of the partners. However, an allocation of depletable
basis under a partnership agreement (where such allocation is not governed
under Section 704(c) of the Code) will be recognized as being in accordance
with the partners' interests in partnership capital under Section 613A(c)(7)(D)
of the Code provided that such an allocation does not give rise to capital
account adjustments under Section 1.704-1(b)(2)(iv)(k) of the Regulations, the
economic effect of which is insubstantial and all other material allocations
and capital account adjustments under the partnership agreement are respected
under Section 704(b) of the Code and the regulations thereunder. Otherwise,
such depletable basis must be allocated among the partners pursuant to Section
613A(c)(7)(D) of the Code in accordance with the partners' actual interests in
partnership capital or income. In addition, in connection with a revaluation
described in Section 1.704-1(b)(2)(iv)(f) of the Regulations, depletable basis
may be reallocated among the partners to the extent permitted by the Section
613A Regulations.

The Section 613A Regulations provide that upon a contribution of money
or other property to the partnership in exchange for a partnership interest,
the partnership shall reallocate the depletable basis of the partnership's oil
and gas properties among the contributing partner and each existing partner.
As a result, the contributing partner is allocated a share of the depletable
basis in each of the partnership's properties, while each existing partner's
share of depletable basis in the partnership's properties is reduced by the
percentage of the basis allocated to the contributing partner. In calculating
the depletable basis of the existing partners for purposes of determining the
share of basis to be reallocated to the contributing partner, the Section 613A
Regulations provide that the depletable basis of the existing partners may be
determined using either the specific assumptions provided by the regulations or
written data provided by the existing partners. If the assumptions are used in
determining depletable basis, it is possible that the depletable basis of the
partnership's existing properties might be reallocated among the existing
partners and the contributing partner in such a way that a portion of the
partners' aggregate bases in such partnership properties is lost. A
partnership generally may avoid the loss of any portion of the aggregate bases
by using written data submitted by the partners. The Partnership Agreement
requires the Partners to submit information regarding their adjusted basis and
depletion deductions with respect to depletable properties of the Partnership.

It is uncertain whether the Partnership will administer the
reallocation of depletable basis among the Class A, Class B and Class C Units
in a manner consistent with the Section 613A Regulations. However, the
Partnership intends to take the position that the provisions of the Partnership
Agreement regarding the allocation of depletable basis of the Partnership's
properties among the Unitholders are consistent with the requirements of the
Section 613A Regulations. With respect to the depletable basis of existing
Partnership property upon the issuance of additional interests in the
Partnership, the Partnership Agreement provides that the depletable basis shall
be reallocated among the existing Unitholders and the Class C Unitholders
admitted pursuant to the Offering in a manner consistent with the Section 613A
Regulations and the principles of Section 704(c) of the Code. The General
Partner anticipates that each person who acquires Class C Units pursuant to the
Offering will be allocated depletable basis in the Partnership's property in
accordance with their proportionate interest in the Partnership's capital.

As a result of the uncertainty expressed above, Counsel is unable to
express an opinion regarding whether the allocation of depletable basis among
the Unitholders is consistent with the requirements of Section 613A of the Code
and, therefore, whether the allocations will be sustained if challenged by the
IRS. If the Partnership's allocations of depletable basis under Section 613A
of the Code were successfully challenged by the IRS, the Unitholders'
respective tax liabilities would be adjusted, with the result that some
Unitholders may be required to pay additional tax.

(g) No Opinions Regarding Allocations. The Partnership intends to
take the position that the allocations of income, gains, losses and deductions
described above between the Unitholders and HEPGP and among the various
Unitholders under the Partnership Agreement and between the Partnership and
HEPGP under the EDPO Agreement and the HEPO Agreement, respectively, are
respected under the Treasury Regulations. However, Counsel is unable to opine
whether such allocations have substantial economic effect under Section 704(b)
of the Code. Counsel's inability to render an opinion in that regard is
attributable to the fact that Counsel is unable to opine whether the allocations
of income, gain, loss and deduction between the Unitholders and HEPGP, and among
the various classes of Unitholders, comply in all respects with the requirements
of Sections 704(c) and 613A(c)(7)(D) of the Code.

No assurance can be given that the IRS will not challenge the
allocations of the Partnership, EDPO or HEPO. If any allocation made in the
Partnership Agreement, the EDPO Agreement or the HEPO Agreement was not
recognized

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for federal income tax purposes, the item that was the subject of such
allocation would be reallocated among the partners in accordance with their
respective interests in such partnership and the partners' respective tax
liabilities would be adjusted, with the result that some Unitholders may be
required to pay additional tax. Any such reallocation would not affect current
cash distributions to the Unitholders, but could affect the amount of a
Unitholder's liquidating distribution.

TAX CONSEQUENCES OF THE PARTNERSHIP'S OPERATIONS

Intangible Drilling and Development Costs. Intangible drilling and
development costs ("IDCs") incurred by the holder of a working interest in an
oil or gas property may be deducted as expenses for federal income tax purposes
if a proper election is made under Section 263(c) of the Code. IDCs are those
expenditures that are incurred in connection with the drilling and completion
of oil and gas wells and that do not give rise to any asset having a salvage
value. The Partnership, EDPO and HEPO have each made an election under Section
263(c) of the Code, thereby allowing a Unitholder to deduct his distributive
share of all intangible drilling and development costs of EDPO and HEPO in the
year in which such costs are paid or incurred, subject to the basis, at-risk
and passive activity loss limitations discussed above. See "Material Federal
Income Tax Considerations--General Features of Partnership
Taxation--Limitations on Deduction of Losses." It is not anticipated under the
allocation provisions of the Partnership Agreement that the Class C Unitholders
will be allocated significant losses or deductions, including deductions for
IDCs. See "Material Federal Income Tax Considerations--General Features of
Partnership Taxation--Tax Allocations."

Notwithstanding an election by a limited partnership to deduct IDCs,
an individual limited partner may elect to deduct his share of IDCs over a
sixty month period beginning with the month in which the IDCs are paid or
incurred by the limited partnership. The provision allowing the sixty month
amortization has not been the subject of administrative or judicial
interpretation and various questions exist concerning the operation of the
provision and its relationship to other Code provisions (such as the recapture
rules and the rules regarding depletion and gain or loss on disposition of the
relevant property). Accordingly, for this reason and due to the administrative
burden that such an election might impose on the Partnership, HEPGP intends to
account for expenses assuming that each Unitholder deducts currently his
allocable share of IDCs.

Subject to the limitations discussed above, a Unitholder who qualifies
as an "independent Producer" will be entitled to deduct his full share of
domestic IDCs for federal income tax purposes. A Unitholder who does not
qualify as an "independent Producer" (in general, an independent Producer is a
person not directly or indirectly involved in the retail sale of oil, natural
gas or derivative products or the operation of a major refinery) may currently
deduct 70% of the IDCs and may amortize the remaining 30% of such costs over a
period of 60 months, except that all costs of dry holes may be deducted in the
year the drilling is completed.

All or a portion of the amounts previously deducted for IDCs with
respect to a property must be recaptured upon the disposition of such property
by the partnership, or upon the disposition of Units by a Unitholder, by
treating the gain, if any, realized on such disposition as ordinary income to
the extent of such amounts.

Depletion. The owner of an economic interest in an oil or gas
property is entitled to a deduction for depletion in connection with the income
derived from the production of oil, gas and other minerals from the property.
The deduction for depletion for any year with respect to any specific property
is the greater of "cost" depletion or "percentage" depletion (if allowable).

Cost depletion for any year is determined by dividing the tax basis of
a property by the sum of the estimated total units (e.g., Bbls of oil or Mcf of
gas) recoverable from the property as of the end of the year plus the units
sold during the year to determine the per-unit allowance and then multiplying
the per-unit allowance by the number of units sold during the year. Deductions
for cost depletion, in the aggregate, cannot exceed the tax basis of the
property to which they relate.

Percentage depletion is equal to 15% (and, in the case of marginal
production, an additional 1%, subject to a maximum increase of 10%, for each
whole dollar by which $20 exceeds the average domestic wellhead price for crude
oil for the immediately preceding fiscal year) of the gross income attributable
to production from a property, subject to the following limitations: (a) the
amount of percentage depletion with respect to any property may not exceed 100%
of

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the taxable income from such property (computed without regard to the allowance
for depletion) and (b) the total amount of percentage depletion for a taxable
year may not exceed 65% of the taxpayer's taxable income for such year
(computed without regard to percentage depletion deductions and certain loss
carrybacks). In addition, percentage depletion generally is only available
with respect to domestic oil and gas production of certain "independent
producers" (in general, an independent Producer is a person not directly or
indirectly involved in the retail sale of oil, natural gas or derivative
products or the operation of a major refinery). An independent Producer may
deduct percentage depletion only to the extent his average daily production
(including his share of production from any partnership of which he is a
partner) does not exceed 1,000 equivalent Bbls (with 6,000 cubic feet of gas
being equal to one Bbl of oil).

Unlike cost depletion, percentage depletion is not limited to the tax
basis of the property, but continues to be allowable as a deduction each year
even after the tax basis has been fully recovered. See "Federal Income Tax
Considerations--Other Tax Consequences--Minimum Tax" below.

Upon the disposition of a property, all amounts previously deducted
for depletion (whether cost depletion or percentage depletion, except for
percentage depletion deductions in excess of the basis of the property), to the
extent that such amounts reduced the basis in the property, generally must be
recaptured by treating the gain, if any, recognized on such disposition as
ordinary income to the extent of such amounts.

A Unitholder's depletion deduction attributable to the Partnership's
properties will be based on his share of the tax basis in such properties. A
Unitholder who acquires Units pursuant to the Offering will be entitled to
compute cost depletion with respect to that portion of the tax basis of the
Partnership's depletable properties that is allocated to him pursuant to the
Partnership Agreement.

Because depletion deductions are considered to be individual
deductions rather than partnership deductions, each Unitholder generally is
responsible for computing his own depletion allowance and maintaining records
with respect to his share of the basis in the Partnership's depletable
properties. However, the Partnership will calculate the depletion deduction
allowable to a Unitholder based upon the Partnership's information gathering
systems.

Depreciation. The allowance for depreciation permits the Partnership
to deduct the cost of tangible personal property (such as pipe, casing, tubing,
storage tanks and pumps) over certain periods. Under the Accelerated Cost
Recovery System, property is divided into several classes. It is anticipated
that most of the new tangible personal property acquired by the Partnership in
the future will be either (i) classified as "seven-year property" which is
depreciable using either the 200% declining balance method with a switch to the
straight-line method at such time as to maximize depreciation deductions or the
straight-line method over a seven-year period; or (ii) depreciated using the
units of production method . Any depreciation deductions claimed with respect
to an asset will reduce the tax basis in that asset.

Upon the disposition of an asset, all amounts previously claimed as
depreciation deductions must be recaptured by treating the gain, if any,
recognized on such disposition as ordinary income to the extent of such
amounts.

Capital Costs. For federal income tax purposes, costs incurred in the
acquisition and geological evaluation of an oil or gas property must be
capitalized. Such costs are recoverable through depletion deductions if the
property is productive or through loss deductions at such time as the property
is abandoned or determined to be worthless if the property is not productive.
Any other capital costs associated with nonproductive wells may be deducted at
such time as the leases upon which such wells are located or the items
themselves are abandoned or determined to be worthless.

Farm-out and Farm-in Transactions. It is possible that the
Partnership may acquire an interest in an oil or gas property in partial or
full consideration for its agreement to drill one or more wells thereon (a
"farm-in" transaction) or that it may transfer an interest in an oil or gas
property in partial or full consideration for an agreement of the transferee to
drill one or more wells thereon (a "farm-out" transaction). The IRS has ruled
that a farm-out or farm-in transaction involving more than one property could
result in taxable income to both parties, even though no cash consideration is
given or received.

The Partnership, in negotiating farm-out or farm-in transactions, will
endeavor to take such steps as may be practicable to minimize the exposure
under such ruling. The application of the ruling in certain fact situations,
however,

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is unclear. Therefore, the IRS may claim that normal farm-out and farm-in
transactions entered into by the Partnership result in taxable gain to the
Partnership in excess of amounts reported, if any, on the Partnership's income
tax returns. If such position of the IRS is ultimately sustained, the
Unitholders would be required to take into account their shares of such taxable
income, although no cash would be distributed the Unitholders with respect to
such income.

Organization and Syndication Costs. Costs paid in connection with the
organization and syndication of the Partnership must be capitalized.
Organization costs (i.e., costs that are incident to the creation of the
Partnership) may be amortized over a period of not less than 60 months.
Syndication costs (i.e., costs incurred to promote the sale of, or to sell,
interests in the Partnership, including the Offering) cannot be amortized or
otherwise deducted. Substantially all the costs incurred in connection with
the Offering will be classified as syndication costs.

Transfer of Cash, Units and Property Interests to HEPGP as
Compensation. HEPGP generally will receive cash or Units equal to 2% of the
acquisition cost of any oil and gas properties, Oil and Gas Interests (as
defined in the Partnership Agreement) and any other Oil and Gas Related Assets
(as defined in the Partnership Agreement) acquired by the Partnership (or any
Operating Partnership or the Joint Venture, as such term is defined in the
Partnership Agreement) as a fee in connection with the acquisition of such
properties interests and related assets. HEPGP will be required to recognize
in the tax years in which the cash or Units are receivable taxable income equal
to the amount of cash received or the fair market value of Units received.

To the extent HEPGP receives Units as an acquisition fee, the
Unitholders may also recognize taxable gain. Specifically, the Partnership
will be deemed to have transferred to HEPGP as compensation for services an
undivided interest in the assets of the Partnership followed immediately
thereafter by a recontribution of such assets by HEPGP to the Partnership for
the Units. This deemed transfer to HEPGP will result in taxable gain to the
Partnership equal to the excess of the fair market value of the undivided
interest in the Partnership assets transferred to HEPGP over the adjusted tax
basis of the Partnership in such assets. Any such gain will be allocated among
the Unitholders in accordance with the provisions of the Partnership Agreement
and taxed as capital gain if the transferred assets were either capital assets
or "Section 1231 assets," except that such gain will be taxed as ordinary
income to the extent it is attributable to the recapture of deductions for
intangible drilling and development costs, depreciation deductions and
depletion deductions. This taxable gain will be allocated among the
Unitholders in accordance with the provisions of the Partnership Agreement.

The Partnership's adjusted tax basis in the Partnership assets that
are treated as conveyed by HEPGP to the Partnership in this deemed transfer
should be equal to the taxable income recognized by HEPGP. Such increase in
the adjusted tax basis of the Partnership's assets should increase HEPGP's
depletion and depreciation deductions as well as decrease HEPGP's gain on
disposition of the assets.

HEPGP also will receive 4% of any oil and gas properties, Oil and Gas
Interests or any other Oil and Gas Related Assets other than Undeveloped
Acreage and Proved Undeveloped Acreage (as such terms are defined in the
Partnership Agreement) acquired by the Partnership (or any Operating
Partnership or the Joint Venture) as a fee in connection with the acquisition
of such properties, interests and related assets. The Partnership will
recognize gain or loss upon the transfer of such 4% interest in an amount equal
to the difference between the fair market value of the interest transferred and
its adjusted tax basis. Any gain recognized by the Partnership will be
allocated among the Unitholders in accordance with the provisions of the
Partnership Agreement. HEPGP will be required to recognize in the tax years in
which the property is received taxable income equal to the fair market value of
the property interests. HEPGP's 4% interests will be held by HEPGP outside of
the Partnership and should not, therefore, have any additional tax effect on
the Unitholders.

The Partnership intends to capitalize the fees paid to HEPGP as part
of the Partnership's adjusted tax basis in the acquired property in an amount
equal to the fair market value of the cash, Units or property interests
received by HEPGP as an acquisition fee. See "Federal Income Tax
Considerations--Tax Consequences of the Partnership's Operations--Capital
Costs."

Acquired Intangible Assets. Subject to the application of certain
anti-churning rules, the Partnership (as well as any Operating Partnership)
should be allowed to amortize its tax basis in purchased intangibles (assuming
that such intangibles are "amortizable Section 197 intangibles" within the
meaning of Section 197 of the Code) over 15 years on

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a straight-line basis under Section 197 of the Code. Each Unitholder will be
allocated a share of such amortization deductions which will reduce the
Unitholder's share of the taxable income of the Partnership.

Section 754 Election. The Partnership and the Operating Partnerships
have made the election permitted by Section 754 of the Code. This election
generally permits a subsequent purchaser of Class C Units to adjust his share
of the basis in the Partnership's properties ("inside basis") pursuant to
Section 743(b) of the Code to fair market value (as reflected by his Class C
Unit purchase price). The Section 743(b) adjustment is attributed solely to
such a purchaser of Class C Units and is not added to the bases of the
Partnership's assets associated with all other Unitholders (for purposes of
this discussion, a Unitholder's inside basis in the Partnership's assets will
be considered to have two components: (1) his share of the Partnership's actual
basis in such assets ("Common Basis"); and (2) his Section 743(b) adjustment
allocated to each such asset). This adjustment will result in the purchaser
claiming depletion and other deductions and reporting his share of the
Operating Partnerships' gain or loss on the sale of its assets, based on his
purchase price for the Class C Units, rather than on the Operating
Partnerships' adjusted tax basis in its assets. This adjustment may favorably
influence the sales price and marketability of the Class C Units if the
purchaser's basis in his Class C Units is greater than such Units' share of the
Operating Partnerships' adjusted tax bases in their assets. However, this
adjustment may negatively influence the sales price and marketability of the
Class C Units if the purchaser's basis in his Class C Units is less than such
Units' share of the Operating Partnerships' adjusted tax bases in their assets.

Proposed Treasury Regulation Section 1.168-2(n) generally requires the
Section 743(b) adjustment attributable to recovery property to be depreciated
as if the total amount of such adjustment were attributable to newly-acquired
recovery property placed in service when the purchaser acquires the Unit.
Similarly, Proposed Treasury Regulation Section 1.197-2(g)(3) generally
requires that the Section 743(b) adjustment attributable to an amortizable
Section 197 intangible must be treated as a newly acquired asset placed in
service when the purchaser acquires the Unit. Under Treasury Regulation
Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Code (rather than cost
recovery deductions under Section 168) is generally required to be depreciated
using either the straight-line method or the 150% declining balance method.
The depreciation and amortization methods and useful lives associated with the
Section 743(b) adjustment, therefore, may differ from the methods and useful
lives generally used to depreciate the Partnership's (or Operating
Partnership's) Common Basis in such properties. See "Material Federal Income
Tax Considerations--Uniformity of Units."

Pursuant to the Partnership Agreement, HEPGP generally is authorized
to make allocations to achieve and maintain the uniformity of Units, even if
such allocations are not consistent with Treasury Regulation Section 1.167(c)-
1(a)(6), Proposed Treasury Regulation Section 1.168-2(n) or Proposed Treasury
Regulation Section 1.197-2(g)(3). In implementing the Section 754 election,
HEPGP will be required to periodically make a number of complex and detailed
allocations, valuations and calculations. In order to avoid undue
administrative expense in effecting the Section 754 election, HEPGP intends to
employ various procedures that will not conform with existing Regulations in a
number of respects and, specifically, will not be consistent with Treasury
Regulation Section 1.167(c)-1(a)(6), Proposed Treasury Regulation Section
1.168-2(n) or Proposed Treasury Regulation Section 1.197-2(g)(3). For the
reasons discussed in the preceding sentence and below, Counsel is unable to
opine whether the Partnership's method of computing and effecting the
depreciation, depletion and amortization adjustments under Section 743 of the
Code, utilized to maintain the uniformity of the economic and tax
characteristics of the Units, will be sustained if challenged by the IRS.

Although Counsel is unable to opine as to the validity of such an
approach, the Partnership (and the Operating Partnerships) intends to
depreciate the portion of the Section 743(b) adjustment attributable to
unrealized appreciation in the value of any contributed property (to the extent
of any unamortized book-tax disparity) using a rate of depreciation or
amortization derived from the depreciation or amortization method and useful
life applied to the Partnership's (or Operating Partnership's) basis of such
property, despite its inconsistency with Treasury Regulation Section
1.167(c)-1(a)(6), Proposed Treasury Regulation Section 1.168-2(n) or Proposed
Treasury Regulation Section 1.197- 2(g)(3). If the Partnership determines that
such position cannot reasonably be taken, the Partnership may adopt a
depreciation or amortization convention under which all purchasers acquiring
Units in the same month would receive depreciation or amortization, whether
attributable to the Partnership's (or Operating Partnership's) Common Basis or
Section 743(b) adjustment, based upon the same applicable rate as if they had
purchased a direct interest in the Partnership's assets. Such an aggregate
approach may result in lower annual depreciation or amortization deductions
than would otherwise be allowable to certain Unitholders.

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The adjustments to be made to the basis of the Operating Partnerships'
assets as a result of the Section 754 elections are complex. The Code, the
Regulations and other authorities contain no guidance as to how the basis
adjustment is to be made in situations similar to the Partnership's and,
consequently, there is no assurance that the procedures used by the Partnership
(and the Operating Partnerships) will not be successfully challenged by the IRS
and that the deductions attributable to them will not be disallowed or reduced.
HEPGP intends to use the foregoing procedures because it thinks they are
reasonable, because they are used by other publicly traded partnerships and
because it would be too expensive and complex to attempt strict compliance with
all of the technical requirements of the Regulations. Counsel expresses no
opinion with regard to the validity of the foregoing procedures. The use of
such procedures may require Unitholders to make subsequent adjustments to
computations of gain or loss on the sale of a Unit and/or to their share of
items of income, gain, deduction and loss from operations of the Partnership
(which may result in adjustments to the Unitholders' respective tax
liabilities, with the result that some Unitholders may be required to pay
additional tax) and could subject the Partnership and Unitholders to penalties.

Certain operating agreements entered into by the Operating
Partnerships with third parties may be treated as partnerships for federal
income tax purposes. It is anticipated that such tax partnerships will not
make Section 754 elections. As a result, subsequent purchasers of Units may
not obtain the full benefit of the Section 754 elections made by the Operating
Partnerships.

HEPGP will use its best efforts to comply with the requirements of the
Code and the Regulations relating to making the basis adjustment and furnishing
information with regard to the basis adjustment. Should the expense of
compliance prove, in the judgment of HEPGP, to exceed the benefit of the
election, however, HEPGP will, as authorized by the Partnership Agreement, seek
the permission of the IRS to revoke the Section 754 elections for the
Partnership and the Operating Partnerships.

Sale of Partnership Property. If the Partnership sells any of its
property (other than production from its properties), gain will be recognized
to the extent that the amount realized on such sale exceeds the tax basis of
such property or loss will be recognized to the extent that the tax basis
exceeds the amount realized. The amount realized will include any money plus
the fair market value of any other property received. If the purchaser assumes
a liability in connection with such purchase or takes the property subject to a
liability, the amount realized also will include the amount of such liability.

If gain is recognized on such sale, the portion of the gain that is
treated as recapture of IDCs, depletion, or depreciation deductions will be
treated as ordinary income. See "Material Federal Income Tax
Considerations--Tax Consequences of the Partnership's Operations--Intangible
Drilling and Development Costs," "Material Federal Income Tax
Considerations--Tax Consequences of the Partnership's Operations--Depletion,"
and "Material Federal Income Tax Considerations--Tax Consequences of the
Partnership's Operations--Depreciation" above. The remainder of such gain
generally will constitute "Section 1231 gain." If loss is recognized on such
sale, such loss generally will constitute "Section 1231 loss."

Each Unitholder must take into account his share of the portion of the
gain that constitutes recapture income as ordinary income and must also take
into account his share of the Section 1231 gains and losses along with his
Section 1231 gains and losses from other sources, subject to the loss
limitations. See "Material Federal Income Tax Considerations--General Features
of Partnership Taxation--Limitations on Deduction of Losses." The
characterization of the Unitholder's share of the Section 1231 gains and
Section 1231 losses attributable to the Partnership's properties as either
ordinary or capital will depend upon the total amount of the Unitholder's
Section 1231 gains and Section 1231 losses from all sources for the taxable
year. Generally, if the total amount of the gains exceeds the total amount of
the losses, all such gains and losses will be treated as capital gains and
losses and if the total amount of the losses exceeds the total amount of the
gains, all such gains and losses will be treated as ordinary income and losses.
Notwithstanding the above, however, a Unitholder's net Section 1231 gains will
be treated as ordinary income to the extent of such Unitholder's net Section
1231 losses during the immediately preceding five years reduced by any amount
of net Section 1231 losses that have previously been "recaptured" pursuant to
this rule.

If a Unitholder is entitled to basis adjustment by reason of the
Section 754 election and a portion of such adjustment is allocated to the
property that is sold, the amount of the gain or loss that such Unitholder will
be required

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to report by reason of such sale will be affected by such basis adjustment.
See "Material Federal Income Tax Considerations--Tax Consequences of the
Partnership's Operations--Section 754 Election" above.

Termination of the Partnership. If Units representing at least a 50%
interest in the capital and profits of the Partnership are sold or exchanged
within any consecutive 12-month period (disregarding successive transfers of
the same Units during such period), the Partnership will terminate for federal
income tax purposes. Such a termination is referred to as a "constructive
termination." When a constructive termination occurs, the Partnership will be
treated as transferring all of its assets and liabilities to a new partnership
in exchange for an interest in the new partnership and, immediately thereafter,
the Partnership will be treated distributing its interest in the new
partnership to its partners in liquidation of the Partnership. A termination
of the Partnership will also cause a termination of EDPO and HEPO.

The Partnership's taxable year will end on the date of the
constructive termination and a new taxable year will begin immediately
thereafter. As a result of the closing of the Partnership's taxable year, a
Unitholder who has a taxable year other than a calendar year may be required to
report more than 12 months of the Partnership's income or loss in his taxable
year in which the constructive termination occurs. In addition, as a result of
the constructive termination, (a) there will be a closing of the Partnership's
taxable year for all partners, (b) the new partnership will be treated as newly
acquiring the depreciable assets of the Partnership and will be required to
restart the depreciable lives of such assets (c) the new partnership will be
required to make new elections for federal income tax purposes (including the
Section 754 election and the election to deduct IDCs) in order to enjoy the
benefit of such elections. Finally, a termination might either accelerate the
application to the Partnership of, or subject the Partnership to, any tax
legislation enacted prior to the termination.

Because the Units will be freely transferable without notice to the
Partnership, the Partnership may not have the ability to determine when a
constructive termination occurs. In any such case, the Partnership may be
subject to penalties for failure to file timely tax returns and may fail to
have in effect certain elections, including the election to deduct IDCs and the
section 754 election.

When the Partnership is actually terminated, each Unitholder will be
required to recognize, in addition to his share of the Partnership's income,
gains, losses and deductions for the period prior to the date of termination,
his share of any gains or losses resulting from the sale or other disposition
of property in liquidation of the Partnership.

Upon the termination of the Partnership, each Unitholder will be
required to recognize gain to the extent that the amount of money distributed
(or deemed to be distributed) to him (including any reduction in his share of
nonrecourse liabilities) exceeds the tax basis of his Units or his at-risk
amount. The Unitholder will not recognize loss unless only money, unrealized
receivables and inventory are distributed and then only to the extent that the
tax basis of his Units exceeds the amount of money plus the tax basis (in the
Partnership's hands) of the property distributed to him. Generally, any gain
or loss will be capital gain or loss; however, if the Unitholder receives or is
deemed to receive more or less than his pro rata share of ordinary income items
(including potential recapture of IDCs), he may be required to recognize
ordinary income or loss.

The tax basis of any property distributed to a Unitholder generally
will be equal to the tax basis of his Units reduced by any money distributed to
him. Such basis generally will be allocated first to ordinary income items in
an amount equal to the Partnership's tax basis in such property, with any
remainder being allocated among the other distributed property as follows: (i)
among such other property in an amount equal to the respective tax bases in the
Partnership's hands, (ii) among such other property with unrealized
appreciation in proportion to such unrealized appreciation; and (iii) among
such other property in proportion to their respective fair market values. Any
Unitholder who has a basis adjustment as a result of the Section 754 election
with respect to any of the Partnership's property will be entitled to include
his basis adjustment in the basis of the property distributed to him. The
holding period of any property distributed will include the period during which
the Partnership held such property if such property was either a capital asset
or a Section 1231 asset in the Partnership's hands; if such property was
neither a capital asset nor a Section 1231 asset in the hands of the
Partnership, the holding period of such property in the hands of the Unitholder
upon such distribution will commence on the day following such distribution.

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SALE OF UNITS

The Units are listed on the American Stock Exchange and sales of Units
may be effected through such exchange. The general tax consequences of such
sales are summarized below.

Allocations Between Transferor and Transferee.

The method currently used by HEP for allocating income, gains, losses
and deductions between transferors and transferees of their Units employs a
monthly convention and a proration method. If a Unit is transferred, the
portion of HEP's income, gains, losses and deductions attributable to such Unit
for the taxable year in which the transfer occurs will be allocated to the
persons who owned such Unit during such year pro rata in accordance with the
number of months during such year that each owned the Unit. For purposes of
this allocation, the person who owned the Unit on the first day of any month is
considered to be the owner of such Unit for that entire month. For example, a
person who purchases one Unit on March 15 and sells such Unit on April 10 of
the same year will be allocated one-twelfth of the portion of HEP's income,
gains, losses and deductions attributable to that Unit for such year. As a
result of this allocation method, the share of the partnership's income, gains,
losses and deductions allocated to and reportable by a Unitholder may not
correspond to the items of income, gain, loss and deduction that actually arose
during the portion of the year that he held his Unit.

The IRS has announced that it intends to issue Regulations under
Section 706(d) of the Code, which governs allocations between transferors and
transferees. Pending the issuance of such Regulations, the IRS appears to
require the use of a daily convention if a proration method is used (pursuant
to which income, gains, losses and deductions attributable to a partnership
interest for a taxable year are allocated to the owners of such interest pro
rata in accordance with the number of days during such year that each owned the
interest) and to permit the use of a semi- monthly convention if an interim
closing method is used (pursuant to which the items of income, gain, loss and
deduction actually arising during a particular month are allocated to the owner
of the interest during the month). In addition, certain Congressional
committee reports appear to restrict the use of a monthly convention to
dispositions of less than all of a partner's interest. Thus, there can be no
assurance that the IRS will not require the Partnership to use a different
allocation method than the one it currently uses. For the reasons stated
above, Counsel is unable to opine whether the Partnership's conventions for
allocating taxable income and losses between the transferor and the transferee
of Units sold within a month is permitted by existing Regulations. If the IRS
were successful in challenging the Partnership's allocation method, the
Unitholders' respective tax liabilities would be adjusted, with the result that
some Unitholders may be required to pay additional tax and it might be
impossible or administratively impractical for the Partnership to use the
allocation method required by the IRS. The Partnership Agreement gives the
General Partner the power to change the Partnership's transferor-transferee
allocation method in order to comply with future Regulations or other
interpretations of Section 706(d) of the Code.

Where a "parent" partnership (such as the Partnership) holds an
interest in a "subsidiary" partnership (such as EDPO or HEPO) and a partner's
interest in the "parent" partnership changes, the items of the "subsidiary"
partnership are to be allocated among the partners of the "parent" partnership
by (its) assigning the appropriate portion of each such item to the appropriate
day in the "parent" partnership's taxable year (based on the attribution of
such items to the days of the "subsidiary" partnership's taxable year) and (ii)
allocating the items assigned to each such day among the partners of the
"parent" partnership based on their interest in such partnership as of the
close of such day. Because of complexities in applying a daily convention for
such allocations, the Partnership's share of items of taxable income and loss
of EDPO and HEPO generally will be determined and allocated among the
Unitholders of record on a monthly basis employing the same monthly convention
to be used for allocating the Partnership's taxable income and loss among
transferors and transferees of Units. There can be no assurance that the IRS
will not require the Partnership to use a different allocation method than the
one it currently uses. If the IRS were successful in challenging the
Partnership's allocation method, the Unitholders' respective tax liabilities
would be adjusted, with the result that some Unitholders may be required to pay
additional tax, and it might be impossible or administratively impractical for
the Partnership to use the allocation method required by the IRS. The General
Partner is authorized to revise the method of allocation, if necessary, in
order to comply with any Regulations or rulings ultimately published.

Recognition of Gain or Loss. When a Unitholder sells a Class C Unit,
he will recognize gain or loss measured by the difference between the amount
realized on the sale and his tax basis in such Unit. The Unitholder's amount

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realized will be equal to the price at which he sells the Unit plus his share
of any nonrecourse liabilities that the Partnership has outstanding at the time
of the sale. For a discussion of the computation of the tax basis in Units,
see "Material Federal Income Tax Considerations--General Features of
Partnership Taxation--Computation of Basis" above and for a discussion of the
allocation of basis to a particular Unit, see "Material Federal Income Tax
Considerations--Sale of Units--Allocation of Basis in Units" below.

To the extent that the portion of the amount realized that is
attributable to the Partnership's ordinary income items (including potential
recapture of IDCs depletion and depreciation) exceeds the portion of the tax
basis allocable to such items (which will generally be zero), the gain will be
treated as ordinary income. So long as the Unitholder holds the Class C Unit
as a capital asset (generally, an asset held as an investment), the remainder
of the gain will be treated as capital gain and any loss recognized on the sale
will be treated as capital loss. The Unitholder will be required to recognize
the full amount of the ordinary income portion even if the amount of the
ordinary income exceeds the overall gain on the sale (in which event, the
Unitholder will also recognize capital loss to the extent the ordinary income
exceeds the overall gain) and even if there is an overall loss on the sale (in
which event, the Unitholder will recognize an offsetting capital loss equal to
the amount of the ordinary income portion and an additional capital loss equal
to the overall loss on the sale).

Net capital gains of individual taxpayers currently are taxed at a
maximum statutory rate (20% for capital assets held for more than 18 months)
which is less than the maximum statutory rate applicable to other income
(39.6%). Net capital gain means the excess of net long-term capital gain over
net short-term capital loss.

It should be noted that certain limitations are applicable to the
deductibility of capital losses. Therefore, capital gains that result from the
sale of Units can be offset by capital losses from other sources, but capital
losses that result from the sale of Units can be deducted only to the extent of
the Unitholder's capital gains from other sources plus, in the case of an
individual, up to $3,000 of taxable income. Any capital losses that cannot be
deducted in a particular year because of the $3,000 limitation can be carried
forward and deducted as capital losses in subsequent years (subject to the same
limitations and any other limitations on the deductibility of losses). See
"Federal Income Tax Considerations--General Features of Partnership
Taxation--Limitation on Deduction of Losses").

Allocation of Basis in Units. The IRS has ruled that a partner
acquiring interests in a partnership in separate transactions at different
prices must maintain an aggregate adjusted tax basis in a single partnership
interest and that, upon sale or other disposition of some of the interests, a
portion of such aggregate adjusted tax basis must be allocated to the
interests sold on the basis of some equitable apportionment method. The ruling
is unclear as to how the holding period is affected by this aggregation
concept. If this ruling is applicable to the holders of Class C Units, the
aggregation of tax bases of a holder of Class C Units effectively prohibits him
from choosing among the Class C Units with varying amounts of unrealized gain
or loss as would be possible in a stock transaction. Thus, the ruling may
result in an acceleration of gain or deferral of loss on a sale of a portion of
a Unitholder's Class C Units. It is not clear whether the ruling applies to
publicly traded partnerships, such as the Partnership, the interests in which
are evidenced by separate interests and, accordingly, Counsel does not opine as
to the effect such ruling will have on the Unitholders. A Unitholder
considering the purchase of additional Units or a sale of Units purchased at
differing prices should consult his tax advisor as to the possible consequences
of the ruling.

Information Filing Requirements. Any Unitholder who sells a Unit
(other than through a broker, as described below) will be required to notify
the Partnership of such transaction in accordance with Regulations under
Section 6050K of the Code and must attach a statement to his federal income tax
return reflecting certain facts regarding the sale. Such notice must be given
in writing within 30 days of the sale (or, if earlier, by January 15 of the
calendar year following the calendar year in which the sale occurred) and must
include the names and addresses of the buyer and the seller, the taxpayer
identification numbers of the buyer and the seller (if known) and the date of
the sale. Unitholders who fail to furnish the information to the Partnership
concerning the sale required by Section 6050K of the Code may be penalized $50
for each such failure. Furthermore, the Partnership is required to notify the
IRS of any sale of a Unit of which it has notice (other than a sale through a
broker, as described below) and to report the names, addresses and taxpayer
identification numbers of the buyer and the seller who were parties to such
transaction, along with all other required information. If the Partnership
fails to furnish this information to the IRS, it may be subject to a penalty of
$50 per failure with an annual maximum penalty of $250,000 (with a penalty of
$100 per failure and no annual limitation in the case of intentional disregard
of this requirement). The Partnership also is required to provide copies of
the information

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it provides to the IRS to the buyer and the seller. If the Partnership fails
to furnish this information to the buyer and the seller, it may be subject to a
penalty of $50 per failure with an annual maximum penalty of $100,000.

These reporting requirements do not apply to a sale of Units by a U.S.
citizen through a broker. Units that are sold through a broker will be subject
to the information return filing requirements of Section 6045 of the Code.
Section 6045 of the Code and the Regulations thereunder provide that a broker
that makes a sale of a partnership interest on behalf of a customer must notify
the IRS of such sale and report to the IRS the name, address and taxpayer
identification number of the customer as well as additional required
information concerning the transaction. The broker must also provide to the
customer a copy of the information provided to the IRS.

UNIFORMITY OF UNITS

Because the Partnership cannot match transferors and transferees of
Class C Units, uniformity of the economic and tax characteristics of the Class
C Units to a purchaser of such Units must be maintained. In the absence of
uniformity, compliance with a number of federal income tax requirements, both
statutory and regulatory, could be substantially diminished. A lack of
uniformity can result from a literal application of Treasury Regulation Section
1.167(c)-1(a)(6), Proposed Treasury Regulation Section 1.168-2(n) or Proposed
Treasury Regulation Section 1.197-2(g)(3) and from the application of the
"ceiling limitation" on the Partnership's ability to make allocations to
eliminate book- tax disparities attributable to contributed properties and
Partnership property that has been revalued and reflected in the partners'
capital accounts ("Adjusted Properties"). Any non-uniformity could have a
negative impact on the value of the Class C Units. See "Material Federal Income
Tax Considerations--Tax Consequences of the Partnership's Operations--Section
754 Election."

The Partnership intends to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value of contributed
property or Adjusted Property (to the extent of any unamortized book-tax
disparity) using a rate of depreciation or amortization derived from the
depreciation or amortization method and useful life applied to the
Partnership's (or Operating Partnership's) basis of such property, despite its
inconsistency with Treasury Regulation Section 1.167(c)-1(a)(6), Proposed
Treasury Regulation Section 1.168-2(n) and Proposed Treasury Regulation Section
1.197-2(g)(3). See "Material Federal Income Tax Considerations--Tax
Consequences of the Partnership's Operations--Section 754 Election." If the
Partnership determines that such a position cannot reasonably be taken, the
Partnership may adopt a depreciation and amortization convention under which
all purchasers acquiring Units in the same month would receive depreciation and
amortization deductions, whether attributable to the Partnership's (or
Operating Partnership's) Common Basis or Section 743(b) basis, based upon the
same applicable rate as if they had purchased a direct interest in the
Partnership's property. If such an aggregate approach is adopted, it may
result in lower annual depreciation and amortization deductions than would
otherwise be allowable to certain Unitholders and risk the loss of depreciation
and amortization deductions not taken in the year that such deductions are
otherwise allowable. This convention will not be adopted if the Partnership
determines that the loss of depreciation and amortization deductions will have
a material adverse effect on the Unitholders. If the Partnership chooses not
to utilize this aggregate method, the Partnership may use any other reasonable
depreciation and amortization convention to preserve the uniformity of the
intrinsic tax characteristics of any Units that would not have a material
adverse effect on the Unitholders. In any event, the Partnership intends to
make adjustments as necessary to maintain uniformity among all Class C
Unitholders. The IRS may challenge any method of depreciating the Section
743(b) adjustment described in this paragraph or the adjustments to existing
Class C Units. If such a challenge were sustained, in either respect, the
uniformity of Units might be affected.

OTHER TAX CONSEQUENCES

Minimum Tax. Individuals are subject to an "alternative minimum tax"
in addition to their regular income tax. The alternative minimum tax is the
excess of (a) 26% of up to $175,000 ($87,500 for a married taxpayer filing a
separate return) of the taxpayer's alternative minimum taxable income in excess
of the taxpayer's exemption amount plus 28% of the taxpayer's remaining
alternative minimum taxable income over (b) the taxpayer's regular tax
liability for the taxable year. The taxpayer's exemption amount is $45,000 in
the case of married taxpayers filing a joint return or a surviving spouse,
$33,750 in the case of a single taxpayer who is not a surviving spouse and
$22,500 in the case of a married taxpayer filing a separate return. The
exemption amount is reduced (but not below zero) by $.25 for each dollar of
alternative minimum taxable income in excess of $150,000 for married taxpayers
filing a joint return or a surviving

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spouse, $112,500 for a single taxpayer who is not a surviving spouse and
$75,000 for a married taxpayer filing a separate return. An individual's
alternative minimum taxable income generally is equal to his taxable income
(recomputed by making certain adjustments) plus the individual's tax preference
items.

Corporations are also subject to an alternative minimum tax. The
corporate minimum tax is the excess of (a) 20% of the amount by which the
corporation's alternative minimum taxable income exceeds $40,000 over (b) the
corporation's regular income tax liability. The $40,000 exemption amount is
reduced by $.25 for each dollar of alternative minimum taxable income in excess
of $150,000. A corporation's alternative minimum taxable income generally is
equal to taxable income (recomputed by making certain adjustments) plus the
corporation's tax preference items.

Because a Unitholder's liability for the alternative minimum tax is
computed by taking into account his regular income tax liability, the extent to
which any tax preference items directly or indirectly resulting from his
investment in Units would be subject to the alternative minimum tax will depend
on the facts of his particular situation. For a taxpayer with substantial tax
preference items, the alternative minimum tax could reduce the after-tax
economic benefit of his investment in Units. Each person considering an
acquisition of Units should consult his tax advisor concerning the impact of
the alternative minimum tax on his investment in Units.

State and Local Taxes.

In addition to federal income taxes, Unitholders may be subject to
state and/or local income taxes, as well as other taxes, that may be imposed by
the various jurisdictions in which the Partnership, EDPO or HEPO own property
or conduct business, as well as being subjected to tax by the Unitholder's
state of domicile. The Partnership, EDPO or HEPO own or may acquire properties
in states that have state income taxes applicable to individuals. As a result,
Unitholders may be required to file state income tax returns and to pay state
income taxes in some or all of these states and may be subject to penalties for
failure to comply such requirements. Some of the states may require the
Partnership, or the Partnership may elect, to withhold a percentage of income
from amounts to be distributed to a Unitholder who is not a resident of the
state. Withholding, the amount of which may be greater or less than a
particular Unitholder's state income tax liability, generally does not relieve
the non-resident Unitholder from the obligation to file a state income tax
return. Amounts withheld may be treated as if distributed to Unitholders for
purposes of determining the amounts distributed by the Partnership to the
Unitholders. In addition, the assets of the Partnership, EDPO and HEPO will
likely be subject to ad valorem tax assessed by the county and other local
political jurisdictions within which such assets are situated. Production from
the wells of the Partnership, EDPO and HEPO may be subject to state taxes on
gross production in certain jurisdictions and a Unitholder might be subjected
to estate or inheritance taxes in such states.

Certain tax benefits that are available to the Unitholder for federal
income tax purposes may not be available to the Unitholder for state or local
income tax purposes and vice-versa. The Partnership intends to supply
Unitholders with information that allows the Unitholders to comply with income
tax obligations, if any, attributable to the various jurisdictions in which the
operating partnerships operate. This information should be used by each
Unitholder and his tax advisor to prepare and file any necessary state and
local tax returns. All state and local tax reporting pertaining to the
Unitholders resulting from their ownership interests in the Partnership is the
obligation of the Unitholders.

EACH PERSON CONSIDERING AN INVESTMENT IN THE PARTNERSHIP SHOULD
CONSULT THEIR TAX ADVISOR CONCERNING THE IMPACT OF STATE AND LOCAL TAXES ON
THEIR OWNERSHIP OF UNITS.

Investment by Tax-Exempt Entities.

Certain entities otherwise generally exempt from federal income tax
generally will be taxed on net unrelated business taxable income in excess of
$1,000. A tax-exempt Unitholder's share of the Partnership's income will
constitute unrelated business taxable income ("UBTI") unless an exclusion
applies. Among the exclusions from UBTI are interest income, royalty income
and gains from the sale of property other than inventory or property held for
sale to customers in the ordinary course of business. However, interest
income, royalty income or gain from the sale of such property otherwise
excluded from tax as UBTI may be subject to tax if the property producing the
income or gain is debt financed. Depending on the investments made by the
Partnership, all or part of the income generated by the Partnership may
constitute UBTI to a tax-exempt Unitholder.

<PAGE> 103
A tax-exempt Unitholder may be required to file a federal income tax
return if its share of gross income from the Partnership (when added to its
gross income from other unrelated business) is $1,000 or more, even if it does
not realize net unrelated business taxable income with respect to its
investment in Units. The Partnership will furnish information annually to
enable tax-exempt Unitholders to determine whether they are obligated by reason
of the ownership of the Units to file federal income tax returns with respect
to unrelated business taxable income.

TAX-EXEMPT ENTITIES ARE URGED TO CONSULT THEIR OWN TAX ADVISORS
CONCERNING THE FEDERAL INCOME TAX CONSEQUENCES OF THE OWNERSHIP OF PARTNERSHIP
INTERESTS.

Nominee Reporting. Persons who hold an interest in the Partnership as
a nominee for another person are required to furnish to the Partnership (i) the
name, address and taxpayer identification number of the nominee and the
beneficial owner; (ii) whether the beneficial owner is (a) a person that is not
a U.S. person, (b) a foreign government, an international organization or any
wholly-owned agency or instrumentality of either of the foregoing or (c) a tax-
exempt entity; (iii) the amount and description of Units held, acquired or
transferred for the beneficial owner; and (iv) certain information including
the dates of acquisitions and transfers, means of acquisitions and transfers,
and acquisition cost for purchases, as well as the amount of net proceeds from
sales. Brokers and financial institutions are required to furnish additional
information, including whether they are U.S. persons and certain information on
Units they acquire, hold or transfer for their own account. A penalty of $50
per failure (up to a maximum of $100,000 per calendar year) is imposed by the
Code for failure to report such information to the Partnership. The nominee is
required to supply the beneficial owner of the Units with the information
furnished to the Partnership.

ERISA Considerations. Fiduciaries of pension, profit sharing or stock
bonus plans, Keogh Plans, and other qualified employee benefit plans and other
plans or arrangements subject to Title its of the Employee Retirement Income
Security Act of 1974 ("ERISA") are required to determine whether an investment
in Units will satisfy the standards set forth in ERISA. Among other factors,
such fiduciaries should consider whether the investment satisfies (a) the
exclusive purpose rule of Section 404(a)(1)(A) of ERISA, (b) the prudence
requirements of Section 404(a)(1)(B) of ERISA, (c) the diversification
requirements of Section 404(a)(1)(C) of ERISA and (d) the requirement of
section 404(a)(1)(D) of ERISA that the investment be in accordance with the
documents and instruments governing the plan or arrangement. IRAs that are not
sponsored by an employer or employee organization and Keogh Plans whose only
participants are partners or sole promoters are not generally subject to ERISA;
however, fiduciaries of such plans should consider whether the investment is
authorized by the appropriate governing instruments. In particular, all
fiduciaries should consider the unrelated business taxable income rules
discussed under "Federal Income Tax Considerations Other Tax Consequences -
Investment by Tax-Exempt Entities" above.

In addition, section 406 of ERISA and section 4975 of the Code (which
applies to IRAs and Keogh Plans that are not subject to ERISA in addition to
plans or arrangements that are subject to ERISA) prohibit a fiduciary of an
employee benefit plan or other arrangement from engaging in certain
transactions involving "plan assets" with parties that are "parties in
interest" under ERISA or "disqualified persons" under the Code with respect to
the plan or arrangement. Neither ERISA nor the Code defines "plan assets." The
United States Department of Labor, however, has issued final regulations
defining "plan assets" for purposes of ERISA and the Code. The Partnership
will qualify for the "publicly offered security" exception contained in such
regulations if the Units are (a) "freely transferable," (b) part of a class of
securities that is "widely held," and (c) are sold as either part of a class of
securities registered under section 12 (b) or 12 (g) of the Exchange Act or
part of an offering of securities to the public pursuant to an effective
registration statement under the Securities Act. The Partnership believes that
the Units should be considered "publicly offered securities" within the meaning
of this exception and that its assets should not be considered "plan assets"
for purposes of such regulations.

If the assets of the Partnership were deemed to be plan assets of
plans or IRAs ("Plans") that are Unitholders, the Partnership, the General
Partner and any other person or entity who exercises control over the assets of
the Partnership would be a fiduciary with respect to such Plans. As
fiduciaries, they would be subject to the fiduciary requirements of ERISA and
would be "parties in interest" and "disqualified persons" with respect to such
Plans. As a result, certain transactions involving the assets of the
Partnership might constitute prohibited transactions. If a prohibited
transaction occurs, any fiduciary with respect to a Plan subject to ERISA that
has engaged in the prohibited transaction could be personally liable to (i)
restore to the Plan any profit realized on the transaction and (ii) reimburse
the Plan for any loss suffered by the Plan as a result of the transaction. In
addition, any disqualified person involved in the prohibited

<PAGE> 104
transaction would be (i) liable for the payment of an excise tax and (ii)
required to correct the prohibited transaction. If a prohibited transaction
occurs with respect to an IRA, the excise tax does not apply; however, the IRA
will lose its tax-exempt status.

Each entity that is or may be subject to ERISA or section 4975 of the
Code should consult its own tax advisors concerning the effect of its ownership
of Units under ERISA and Section 4975 of the Code.

ADMINISTRATIVE MATTERS

Returns and Audits. The Partnership, EDPO and HEPO each uses a
calendar year for income tax purposes. Each Unitholder receives a report each
year showing his share of the Partnership's income, gains, losses and
deductions for the preceding year and other reasonably available information
necessary for the preparation of his individual federal income tax returns. It
will be the responsibility of each Unitholder, however, to complete and file
his individual returns. A partner must report partnership items on his own tax
return consistently with the manner they are reported on the partnership's
return, unless the inconsistency is identified on the partner's return.
Therefore, each Unitholder should complete his own individual federal income
tax return, to the extent that it relates to his share of the Partnership's tax
items, in a manner that is consistent with the tax reporting information that
he receives from the Partnership, unless he specifically identifies any
inconsistency on his own return. Intentional or negligent disregard of this
consistency requirement may subject the Unitholder to substantial penalties.

The Partnership, EDPO and HEPO each maintains its books in accordance
with the accrual method of accounting and the federal income tax returns will
be filed in accordance with that method. The Regulations provide that no
method of accounting is acceptable unless, in the opinion of the IRS, it
clearly reflects income. Accordingly, there can be no assurance that the IRS
will not seek to require the Partnership or an operating partnership to treat
particular items under a method of accounting different from that adopted on
the basis that, with respect to such items, the use of the method adopted does
not clearly reflect income. This could result in adverse tax consequences to
the Unitholders.

Although the Partnership is not required to pay any federal income
tax, it must nevertheless file information returns. These returns are subject
to audit by the IRS. The tax liability of each Unitholder with respect to any
item of the Partnership's income, gains, losses, or deductions is determined at
the partnership level in a unified partnership proceeding. In addition,
pursuant to the Taxpayer Relief Act of 1997, any penalty which relates to an
adjustment to a partnership item is determined at the partnership level for
partnership tax years ending after August 5, 1997. The Taxpayer Relief Act of
1997 also alters the tax reporting system and the deficiency collection system
applicable to large partnerships and would make certain additional changes to
the treatment of large partnerships, such as the Partnership. These provisions
are intended to simplify the administration of the tax rules governing large
partnerships. The application of these new rules are optional and the General
Partner has not determined whether the Partnership will elect to have these
provisions apply to the Partnership and the Unitholders. The General Partner
of the Partnership is designated the "tax matters partner," and, as such, has
primary responsibility for partnership-level matters involving the IRS,
including the power to extend the statute of limitations for all partners as to
partnership items. The General Partner, under some circumstances, may enter
into settlement agreements with the IRS concerning items that will be binding
on each Unitholder who owns less than a 1% interest in the Partnership. In the
absence of a settlement, the General Partner, as the tax matters partner, may
choose to litigate, in which event all Unitholders would have the right to
participate and, regardless of participation, would be bound by the outcome of
the litigation. Individual partners (including partners who own less than a 1%
interest in the Partnership) generally have certain rights under the
partnership audit rules, including the right to elect not to be bound by any
settlement agreement entered into by the tax matters partner on his behalf and
the right to aggregate their interests into groups of 5% or more for purposes
of receiving direct notice from the IRS of commencement or completion of
administrative proceedings. Although the IRS is required to notify a
Unitholder of the commencement or completion of administrative proceedings only
if the Unitholder holds a 1% or more interest in the Partnership, the
Partnership intends to so notify all other Unitholders.

If the Partnership were audited and the IRS were successful in
adjusting partnership items, such adjustments would change the federal income
tax liabilities of Unitholders and possibly require each Unitholder to file an
amended tax return. If any additional tax is due, a Unitholder will also be
required to pay the tax determined to be due, the interest

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<PAGE> 105
on such tax deficiency and any applicable penalty. In addition, any audit of
the Partnership's tax return could result in an audit of a Unitholder's entire
tax return and could result in changes to non-partnership items.

Possible Penalties. If there is an underpayment of a Partner's tax
liability attributable to misstatement of his allocable share of Partnership
items, the Partner may be liable for a penalty equal to 20% of such
underpayment. In general, an understatement of tax liability for this purpose
includes negligence or disregard for the rules, a substantial understatement of
income tax or a substantial valuation misstatement. An understatement of tax
liability is substantial if it exceeds the greater of 10% of the tax required
to be shown on the return for the taxable year or $5,000 ($10,000 for certain
corporations). For this purpose, the amount of an understatement does not
include any portion of the understatement for which there existed "substantial
authority" for the position of the taxpayer or with respect to which adequate
disclosure of the relevant facts was made on the return or in a schedule to the
return and provided that there was a reasonable basis for the position taken on
the return. The Regulations provide that disclosure regarding the tax
treatment of partnership items generally is to be made on the return of the
partnership or on an attachment thereto rather than on the return of any
partner. A Partner may make adequate disclosure on his return, however, by
attaching a statement to such return and by filing a copy of such statement
with the IRS Service Center with which the Partnership files its return. In
the case of a "tax shelter," however, the disclosure exception does not apply
and the exception for substantial authority applies only if there is both
substantial authority for the position and the taxpayer "reasonably believed
that the tax treatment of such item by the taxpayer was more likely than not
the proper treatment". With respect to corporate taxpayers, however, there is
no "substantial authority" exception when tax shelter items are involved. In
such a case, a corporation may avoid the substantial understatement penalty
only by showing that it acted with reasonable cause and in good faith in its
treatment of the tax shelter item. A "tax shelter", for this purpose, includes
a partnership the principal purpose of which is the avoidance or evasion of
federal income tax. The Partnership believes that its principal purpose is to
generate income from its oil and gas activities and, accordingly, that it is
not a "tax shelter" within the meaning of the substantial understatement
penalty provision.

A substantial valuation misstatement exists if the value of any
property (or the adjusted basis of any property) claimed on a tax return is
200% or more of the amount determined to be the correct amount of such
valuation or adjusted basis. No penalty is imposed unless the portion of the
underpayment attributable to a substantial valuation misstatement exceeds
$5,000 ($10,000 for most corporations). If the valuation claimed on a return
is 400% or more than the correct valuation, the penalty imposed increases to
40%.

A publicly traded partnership, such as the Partnership, may encounter
situations in which it is difficult for the partnership to fully and accurately
comply with all federal tax reporting requirements. Ownership of partnership
interests by nominees (e.g., in street name of a broker) increases this
difficulty. If a partnership fails to comply with such requirements, certain
penalties could be assessed against the partnership or its partners.

Tax Shelter Registration. The Partnership is subject to rules
regarding the registration of "tax shelters." The registration requirements
provide that a tax shelter organizer must register the tax shelter investment
with the IRS and describe, among other things, the tax benefits associated with
such investment. The IRS is required to assign each tax shelter a registration
number and the tax shelter organizer must notify the investors regarding the
tax shelter's registration number. The investor must report this number on a
form attached to his individual income tax return for any year in which he
claims any income, gain, loss, deduction, or credit with respect to such tax
shelter.

The Partnership is registered as a "tax shelter" with the IRS. The
Partnership's tax shelter identification number is 85193000156. The
Partnership will supply such identification number to Unitholders along with
their annual tax reporting information package. Any person reporting income,
loss, deduction or credit attributable to the Partnership will be obligated to
provide such tax shelter registration number on Form 8271 and attach such form
to his return. Failure to include such number with the return could result in
the imposition of a penalty of $250 for each such failure unless due to
reasonable cause. If a Unitholder sells or otherwise transfers a Unit, he must
give the transferee a prescribed written statement containing the registration
number with the instructions concerning its use, subject to a $100 penalty for
each failure to do so.

ISSUANCE OF A REGISTRATION NUMBER DOES NOT INDICATE THAT THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED
BY THE INTERNAL REVENUE SERVICE.

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<PAGE> 106
Investor Lists. Because the Partnership will be registered as a tax
shelter, it will be required to maintain a list identifying each person who was
sold an interest in such shelter including the investor's name, address, and
taxpayer identification number, the number of Units acquired and the date of
the acquisition, the name of the person from whom the Units were acquired and
certain other information. This list must be made available to the IRS upon
request and all information required to be on such list must be retained for
seven years. Each Unitholder generally will be required to maintain a list
with respect to any transferee of his Units. The penalty for failure to
maintain a list of investors is $50 for each person with respect to whom there
is a failure, unless such failure is due to reasonable cause and not willful
neglect. HEPGP, as general partner of the Partnership, will use its best
efforts to comply with this rule.

INVESTMENT IN THE PARTNERSHIP BY EMPLOYEE BENEFIT PLANS

An investment in the Partnership by an employee benefit plan is
subject to certain additional considerations because the investments of such
plans are subject to the fiduciary responsibility and prohibited transaction
provisions of ERISA, and restrictions imposed by Section 4975 of the Code. As
used herein, the term "employee benefit plan" includes, but is not limited to,
qualified pension, profit sharing and stock bonus plans, Keogh plans,
simplified employee pension plans and tax deferred annuities or Individual
Retirement Accounts established or maintained by an employer or employee
organization. Among other things, consideration should be given to (a) whether
such investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in
making such investment, such plan will satisfy the diversification requirement
of Section 404(a)(1)(C) of ERISA; and (c) whether such investment will result
in recognition of unrelated business taxable income by such plan and, if so,
the potential after-tax investment return. See "Material Federal Income Tax
Considerations--Other Tax Consequences--Investment by Tax-Exempt Entities."
The person with investment discretion with respect to the assets of an employee
benefit plan (a "fiduciary") should determine whether an investment in the
Partnership is authorized by the appropriate governing instrument and is a
proper investment for such plan.

Section 406 of ERISA and Section 4975 of the Code (which also applies
to Individual Retirement Accounts that are not considered part of an employee
benefit plan) prohibit an employee benefit plan from engaging in certain
transactions involving "plan assets" with parties that are "parties in
interest" under ERISA or "disqualified persons" under the Code with respect to
the plan.

In addition to considering whether the purchase of Units is a
prohibited transaction, a fiduciary of an employee benefit plan should consider
whether such plan will, by investing in the Partnership, be deemed to own an
undivided interest in the assets of the Partnership, with the result that the
General Partner also would be a fiduciary of such plan and the operations of
the Partnership would be subject to the regulatory restrictions of ERISA,
including its prohibited transaction rules, as well as the prohibited
transaction rules of the Code.

The Department of Labor regulations provide guidance with respect to
whether the assets of an entity in which employee benefit plans acquire equity
interests would be deemed "plan assets" under certain circumstances. Pursuant
to these regulations, an entity's assets would not be considered to be "plan
assets" if, among other things, (a) the equity interest acquired by employee
benefit plans are publicly offered securities, i.e., the equity interests are
widely held by 100 or more investors independent of the issuer and each other,
freely transferable and registered pursuant to certain provisions of the
federal securities laws, (b) the entity is an "operating company," i.e., it is
primarily engaged in the production or sale of a product or service other than
the investment of capital either directly or through a majority owned
subsidiary or subsidiaries or (c) there is no significant investment by benefit
plan investors, which is defined to mean that less than 25% of the value of
each class of equity interest (disregarding certain interests held by the
General Partner, its affiliates, and certain other persons) is held by the
employee benefit plans referred to above, Individual Retirement Accounts and
other employee benefit plans not subject to ERISA (such as governmental plans).
The Partnership's assets should not be considered "plan assets" under these
regulations because it is expected that the investment will satisfy the
requirements in (a) and (b) above and may also satisfy the requirements in (c).

Plan fiduciaries contemplating a purchase of Units should consult with
their own counsel regarding the consequences under ERISA and the Code in light
of the serious penalties imposed on persons who engage in prohibited
transactions or other violations.

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UNDERWRITING

The Partnership has entered into an Underwriting Agreement (the
"Underwriting Agreement") with the underwriters listed in the table below (the
"Underwriters"), for whom Principal Financial Securities, Inc., Ladenburg
Thalmann & Co. Inc., Wheat First Butcher Singer and First Union Capital
Markets Corp. are acting as representatives (the "Representatives"). Subject
to the terms and conditions of the Underwriting Agreement, the Partnership has
agreed to sell to the Underwriters, and each of the Underwriters has severally
agreed to purchase, the number of Class C Units set forth opposite each
Underwriters' name in the table below:

<TABLE>
<CAPTION>
UNDERWRITER NUMBER OF UNITS
- ----------- ---------------
<S> <C>
Principal Financial Securities, Inc. . . . . . . . . . . . . . . . . . .

Ladenburg Thalmann & Co. Inc. . . . . . . . . . . . . . . . . . . . . . .
Wheat First Butcher Singer . . . . . . . . . . . . . . . . . . . . . . .

First Union Capital Markets Corp. . . . . . . . . . . . . . . . . . . . .
---------

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,500,000
==========
</TABLE>

Subject to the terms and conditions of the Underwriting Agreement, the
Underwriters have agreed to purchase all of the Class C Units being sold to the
public pursuant to the Underwriting Agreement, if any is purchased (excluding
Class C Units covered by the over-allotment option granted therein). In the
event of a default by any Underwriter, the Underwriting Agreement provides
that, in certain circumstances, purchase commitments of the nondefaulting
Underwriters may be increased or decreased or the Underwriting Agreement may be
terminated.

The Representatives have advised the Partnership that the Underwriters
propose to offer the Class C Units directly to the public at the public
offering price set forth on the cover page of this Prospectus and to certain
dealers at such price less a concession of not more than $_____ per Class C
Unit. Additionally, the Underwriters may allow, and such dealers may reallow,
a concession of not in excess of $_____ per Class C Unit to certain other
dealers. After the offering, the initial public offering price and other
selling terms may be changed by the Underwriters.

The Partnership has granted to the Underwriters an option, exercisable
by the Representatives within 30 days after the date of the Underwriting
Agreement, to purchase up to 375,000 Class C Units at the same price per share
to be paid by the Underwriters for the other shares offered hereby. If the
Underwriters purchase any of such additional Units pursuant to this option,
each Underwriter will be committed to purchase such additional Units in
approximately the same proportion as set forth in the table above. The
Underwriters may exercise such option only for the purpose of covering
over-allotments, if any, made in connection with the distribution of the Class
C Units offered hereby.

The offering of the Class C Units is made for delivery when, as and if
accepted by the Underwriters and subject to prior sale and to withdrawal,
cancellation or modification of the offering without notice. The Underwriters
reserve the right to reject an order for the purchase of Class C Units in whole
or in part.

The Representatives have advised the Partnership that the Underwriters
will not confirm sales of Class C Units to accounts over which they exercise
discretionary authority.

The Partnership and Hallwood G.P.'s executive officers and directors
have agreed that, without the prior written consent of Principal Financial
Securities, Inc., they will not sell or otherwise dispose of any Class C Units
for a period of 180 days after the date of this Prospectus, other than as gifts
to family members and transfers to wholly owned affiliates.

Because the National Association of Securities Dealers, Inc. ("NASD")
views the Class C Units offered hereby as interests in a direct participation
program, the offering is being made in compliance with Rule 2810 of the NASD's

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Conduct Rules. Investor suitability of the Class C Units should be judged
similarly to the suitability of other securities which are listed for trading
on a national securities exchange.

The Company has agreed to indemnify the Underwriters and their
controlling persons against certain liabilities, including liabilities under
the Securities Act arising out of or based upon untrue statements or provisions
in this Prospectus or the Registration Statement of which the Prospectus is a
part, and to contribute to payments the Underwriters may be required to make in
respect thereof (including legal and other defense costs and expenses).

The Representatives, on behalf of the Underwriters, may engage in
over-allotment, stabilizing transactions, syndicate covering transactions and
penalty bids in accordance with Regulation M under the Exchange Act.
Over-allotment involves syndicate sales in excess of the offering size, which
creates a syndicate short position. Stabilizing transactions permit bids to
purchase the underlying security so long as the stabilizing bids do not exceed
a specified maximum. Syndicate covering transactions involve purchases of
Class C Units in the open market after the distribution has been completed in
order to cover syndicate short positions. Penalty bids permit the
Representatives to reclaim a selling concession from a syndicate member when
the Class C Units originally sold by such syndicate member are purchased in a
syndicate covering transaction to cover syndicate short positions. Such
stabilizing transactions, syndicate covering transactions and penalty bids may
cause the price of the Class C Units to be higher than it would otherwise be in
the absence of such transactions. These transactions may be effected on the
American Stock Exchange or otherwise and, if commenced, may be discontinued at
any time.

The Representatives have performed investment banking and other
financial advisory services for the Partnership in the past, for which they
have received customary compensation.

LEGAL MATTERS

The validity of the Class C Units will be passed upon for the
Partnership by Jenkens & Gilchrist, A Professional Corporation, Dallas, Texas.
Certain legal matters in connection with the Class C Units will be passed upon
for the Underwriters by Vinson & Elkins L.L.P., Dallas, Texas.

EXPERTS

The consolidated financial statements of the Partnership as of
December 31, 1996 and 1995 and for each of the three years in the period ended
December 31, 1996, included and incorporated by reference in this Prospectus
have been audited by Deloitte & Touche LLP, independent auditors, as stated in
their reports, which are included and incorporated by reference herein, and
have been so included and incorporated in reliance upon the report of such firm
given upon their authority as experts in accounting and auditing.

The information included and incorporated by reference herein
regarding the total proved reserves of the Partnership was prepared by the
HPI's in-house engineers. A portion was reviewed by Williamson Petroleum
Consultants, Inc. as stated in their letter report with respect thereto. The
reserve review letter of Williamson Petroleum Consultants, Inc. is filed as an
exhibit to the Registration Statement of which this Prospectus is a part, in
reliance upon the authority of said firm as experts with respect to the matters
covered by its report and the giving of its report.

AVAILABLE INFORMATION

The Partnership has filed with the SEC in Washington, D.C., a
Registration Statement on Form S-1 (the "Registration Statement") under the
Securities Act, with respect to the securities offered by this Prospectus.
Certain of the information contained in the Registration Statement is omitted
from this Prospectus, and reference is hereby made to the Registration
Statement and exhibits and schedules relating thereto for further information
with respect to the Partnership and the securities offered by this Prospectus.
The Partnership is subject to the informational requirements of the Exchange
Act, and, in accordance therewith, files reports and other information with the
SEC. Such reports and other information are available for inspection at, and
copies of such materials may be obtained upon payment of the fees prescribed
therefor by the rules and regulations of the SEC from, the SEC at its principal
offices located at Judiciary Plaza, 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549, and at the Regional Offices of the SEC located at
Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois
60661-2511, and at 7 World Trade Center, New

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York, New York 10048 or may be obtained on the Internet at http://www.sec.gov.
In addition, the Class C Units of the Partnership are traded on the American
Stock Exchange, and such reports and other information may be inspected at the
offices of the American Stock Exchange, Inc., 86 Trinity Place, New York, New
York 10006-1881.

DOCUMENTS INCORPORATED BY REFERENCE

The following documents or portions thereof filed by the Partnership
are hereby incorporated by reference in this Prospectus:

(i) the Partnership's Annual Report on Form 10-K for the fiscal
year ended December 31, 1996;

(ii) the Partnership's Quarterly Reports on Form 10-Q for the
quarters ended March 31, 1997, June 30, 1997 and September 30,
1997;

(iii) the description of the Class C Units set forth in the
Registration Statement on Form 8-A, filed with the SEC on
December 8, 1995, including any amendment or report filed for
the purpose of updating such description.

In addition, all documents subsequently filed by the Partnership
pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the
date of this Prospectus and prior to the termination of the offering of Class C
Units made hereby shall be deemed to be incorporated by reference into this
Prospectus and to be a part hereof from the date of filing of such documents.
Any statement contained herein or in a document incorporated or deemed to be
incorporated by reference herein shall be deemed to be modified or superseded
for the purposes of this Prospectus to the extent that a statement contained
herein or in any subsequently filed document which is or is deemed to be
incorporated by reference herein modifies or supersedes such statement. Any
such statement so modified or superseded shall not be deemed, except as so
modified or superseded, to constitute a part of this Prospectus.

The Partnership will provide without charge to each person to whom a
copy of this Prospectus is delivered, upon oral or written request of such
person, a copy of any and all of the documents incorporated by reference herein
(other than exhibits and schedules to such documents, unless such exhibits or
schedules are specifically incorporated by reference into such documents).
Such requests should be directed to Hallwood Energy Partners, L.P., 4582 South
Ulster Street Parkway, Suite 1700, Denver, Colorado 80237, Attention: Investor
Relations.

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GLOSSARY OF CERTAIN TERMS

The definitions set forth below shall apply to the indicated terms as
used in this Prospectus. All volumes of natural gas referred to herein are
stated at the legal pressure base of the state or area where the reserves exist
and at 60 degrees Fahrenheit and in most instances are rounded to the nearest
major multiple.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d. Stock tank barrels per day.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

Class A Units. A Unit representing a fractional part of the
partnership interests of all limited partners of the Partnership and their
assignees and having the rights and obligations specified with respect to a
Class A Unit in the Partnership Agreement.

Class B Units. A Unit representing a fractional part of the
partnership interests of all limited partners of the Partnership and their
assignees and having the rights and obligations specified with respect to a
Class B Unit in the Partnership Agreement.

Class C Units. A Unit representing a fractional part of the
partnership interests of all limited partners of the Partnership and their
assignees and having the rights and obligations specified with respect to a
Class C Unit in the Partnership Agreement.

Code. The Internal Revenue Code of 1986, as amended.

Completion. The installation of permanent equipment for the
production of oil or gas or, in the case of a dry hole, the reporting of
abandonment to the appropriate agency.

Counsel. Jenkens & Gilchrist, a Professional Corporation, counsel to
the Partnership.

Credit Facilities. Collectively, the Second Amended and Restated
Credit Agreement of the Partnership and the Amended and Restated Note Purchase
Agreement of the Partnership, as amended and restated as of May 31, 1997.

Delaware Act. The Delaware Revised Uniform Limited Partnership Act, 6
Del. C. Sections 17-101, et seq., as amended, supplemented or restated from
time to time, and any successor to such statute.

Developed acreage. The number of acres which are allocated or
assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

EDPO. EDP Operating, Ltd., a Delaware limited partnership, and one of
the Partnership's Operating Partnerships.

Exploratory well. A well drilled to find and produce oil or gas
reserves not classified as proved, 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.

Farm-in or farm-out. An agreement whereunder the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the

106
<PAGE> 111
assignee is required to drill one or more wells in order to earn its interest
in the acreage. The assignor usually retains a royalty or reversionary interest
in the lease. The interest received by an assignee is a "farm-in" while the
interest transferred by the assignor is a "farm-out."

Field. An area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.

Finding costs. Costs associated with acquiring and developing proved
oil and gas reserves which are capitalized by the Partnership pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling and
completing wells.

Gas Balancing. Monitoring the difference between the volume of gas
from a well actually received by each owner and the volume that should be
allocated to such owner based on the percentage of the well owned.

General Partner. HEPGP Ltd., a Colorado limited partnership, and its
successors and permitted assigns as general partner of the Partnership and the
Operating Partnerships.

Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.

Hallwood G.P. Hallwood G.P., Inc., a Delaware corporation, and the
general partner of the General Partner.

Hallwood Group. The Hallwood Group Incorporated, a Delaware
corporation, and the parent of Hallwood G.P..

HCRC. Hallwood Consolidated Resources Corporation, a publicly traded
Delaware corporation, the common stock of which the Partnership owns 46%.

HEC. Hallwood Energy Corporation, the previous general partner of the
Partnership.

HEPGP. HEPGP Ltd., a Colorado limited partnership, and the General
Partner of the Partnership.

HEPO. HEP Operating Partners, L.P., a Delaware limited partnership,
and one of the Partnership's Operating Partnerships.

HPI. Hallwood Petroleum, Inc., a Delaware corporation, that is a 96%
owned subsidiary of the Partnership.

IRS. The United States Internal Revenue Service.

Mbbls. One thousand barrels of crude oil or other liquid
hydrocarbons.

Mbbls/d. One thousand barrels of crude oil or other liquid
hydrocarbons per day.

Mcf. One thousand cubic feet.

Mcf/d. One thousand cubic feet per day.

Mcfe. One thousand cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids, which approximates the relative energy content of crude oil,
condensate and natural gas liquids as compared to natural gas. Prices have
historically been higher or substantially higher for crude oil than natural gas
on an energy equivalent basis.

Mmbtu. One million British Thermal Units, which is the English system
unit of heat used to measure the heat content of natural gas.

Mmcf. One million cubic feet.

107
<PAGE> 112
Mmcf/d. One million cubic feet per day.

Mmcfe. One million cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

Net acres or net wells. The sum of the fractional working interests
owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Operating Partnerships. EDP Operating, Ltd., a Delaware limited
partnership, and HEP Operating Partners, L.P., a Delaware limited partnership,
and any successors thereto.

Operating Partnership Agreements. The limited partnership agreements
governing the Operating Partnerships, included as exhibits to the registration
statement of which this prospectus is a part.

Partnership. Hallwood Energy Partners, L.P., a publicly traded
Delaware limited partnership.

Partnership Agreement. The Third Amended and Restated Agreement of
Limited Partnership of the Partnership as it may be amended, restated or
supplemented from time to time.

Present value. When used with respect to oil and gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using
prices and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

Proved developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves. Proved developed reserves that
are expected to be recovered from completion intervals currently open in
existing wells and able to produce to market.

Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas
and natural gas liquids that 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 spacing rules for purposes of recovering proved
undeveloped reserves.

Proved undeveloped reserves. Proved 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.

Recompletion. The completion for production of an existing well bore
in another formation from that in which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

108
<PAGE> 113
Royalty interest. An interest in an oil and gas property entitling
the owner to a share of oil or gas production free of costs of production.

Shut-in Well. A producing well that is not currently producing oil or
gas.

Successful Well. A well for which production casing has been run for
a completion attempt.

3-D seismic. Advanced technology method of detecting accumulations of
hydrocarbons identified through a three- dimensional picture of the subsurface
created by the collection and measurement of the intensity and timing of sound
waves transmitted into the earth as they reflect back to the surface.

2-D seismic. A two-dimensional seismic picture of the subsurface.

Transfer Agent. Registrar & Transfer & Co. or such bank, trust
company or other person (including the General Partner or one of its
affiliates) as shall be appointed from time to time by the Partnership to act
as registrar and transfer agent for the Units.

Transfer Application. The application which all purchasers of Class C
Units in this Offering and purchasers of Class C Units in the open market who
wish to become Class C Unitholders of record must deliver before the transfer
of such Class C Units will be registered and before cash distributions and
federal income tax allocations will be made to the transferee. A form of
Transfer Application is included in this Prospectus as Appendix A.

Underwriters. The underwriters of the Offering, for which Principal
Financial Securities, Inc., Ladenburg Thalmann & Co. Inc., Wheat First Butcher
Singer and First Union Capital Markets Corp. are acting as the representatives.

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 gas regardless of whether such acreage contains proved
reserves.

Unit. Any of a Class A Unit, Class B Unit or Class C Unit.

United States Citizen. (a) a citizen of the United States, (b) a
corporation organized under the laws of the United States or of any state or
territory thereof, provided that none of the stock of the corporation is owned,
held or controlled by a non-citizen who is a citizen of a country that denies
to United States citizens or corporations privileges to own interests in oil
and gas leases similar to the privileges of non-citizens to own interest in oil
and gas leases on federal lands ("United States Corporation") or (c) an
association (including a partnership or a trust) each of the members of which
is a citizen of the United States or a United States Corporation.

Unitholder. The holder of record of a Unit.

Working interest. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.

Workover. Major remedial operations required to maintain, restore or
increase production rates.

109
<PAGE> 114

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P. Page
----
<S> <C>
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . F-2

Consolidated Balance Sheets at December 31, 1996 and 1995 . . . . . . . . . . . . F-3

Consolidated Statements of Operations for the years
ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . F-5

Consolidated Statements of Partners' Capital for the
years ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . F-6

Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . F-7

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . F-8

Supplemental Oil and Gas Reserve Information - (Unaudited) . . . . . . . . . . . F-23

Consolidated Balance Sheet at September 30, 1997 (Unaudited) . . . . . . . . . . F-27

Consolidated Statements of Operations for the nine months ended
September 30, 1997 and 1996 (Unaudited) . . . . . . . . . . . . . . . . . . . . F-30

Consolidated Statements of Cash Flows for the nine months ended
September 30, 1997 and 1996 (Unaudited) . . . . . . . . . . . . . . . . . . . . F-31

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . F-34

HEPGP Ltd.

Balance Sheets at September 30, 1997 and
December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-35

Notes to Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-36

Supplemental Oil and Gas Reserve Information . . . . . . . . . . . . . . . . . . F-39
</TABLE>

F-1
<PAGE> 115
INDEPENDENT AUDITORS' REPORT

TO THE PARTNERS OF HALLWOOD ENERGY PARTNERS, L.P.:

We have audited the consolidated financial statements of Hallwood Energy
Partners, L.P. as of December 31, 1996 and 1995 and for each of the three years
in the period ended December 31, 1996, listed on page F-1. These financial
statements are the responsibility of the partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Hallwood Energy Partners, L.P. at
December 31, 1996 and 1995, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1996 in
conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Denver, Colorado
February 28, 1997

F-2
<PAGE> 116
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)

<TABLE>
<CAPTION>
December 31,
--------------------------
1996 1995
-------- ---------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 5,540 $ 4,977
Accounts receivable:
Oil and gas revenues 9,405 6,767
Trade 4,507 2,860
Due from affiliates 2,808
Prepaid expenses and other current assets 928 1,091
--------- ---------
Total 20,380 18,503
--------- ---------

PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method):
Proved mineral interests 607,875 601,323
Unproved mineral interests - domestic 1,244 684
Furniture, fixtures and other 3,366 3,090
--------- ---------
Total 612,485 605,097

Less accumulated depreciation, depletion,
amortization and property impairment (523,936) (510,171)
--------- ---------
Total 88,549 94,926
--------- ---------

OTHER ASSETS
Investment in common stock of HCRC 13,700 11,491
Deferred expenses and other assets 163 232
--------- ---------
Total 13,863 11,723
--------- ---------

TOTAL ASSETS $ 122,792 $ 125,152
========= =========
</TABLE>

(Continued on the following page)

F-3
<PAGE> 117
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)

<TABLE>
<CAPTION>
December 31,
-----------------------
1996 1995
--------- ---------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 15,185 $ 17,344
Due to affiliates 159
Net working capital deficit of affiliate 581 5,061
Current portion of contract settlement 374
Current portion of long-term debt 5,810 87
--------- ---------
Total 21,735 22,866
--------- ---------

NONCURRENT LIABILITIES
Long-term debt 29,461 37,557
Contract settlement 2,512 2,397
Deferred liability 1,533 1,718
--------- ---------
Total 33,506 41,672
--------- ---------

Total Liabilities 55,241 64,538
--------- ---------

MINORITY INTEREST IN AFFILIATES 3,336 3,042
--------- ---------

COMMITMENTS AND CONTINGENCIES (NOTE 14)

PARTNERS' CAPITAL
Class A Units - 9,977,254 Units issued, 9,077,949 and
9,193,159 outstanding in 1996 and 1995, 61,487 59,614
respectively
Class B Subordinated Units - 143,773 Units issued
and outstanding 1,254 1,062
Class C Units - 664,063 Units issued and outstanding in
1996 5,146

General Partner 3,307 2,981
Treasury Units - 899,305 and 784,095
Units in 1996 and 1995, respectively (6,979) (6,085)
--------- ---------
Partners' Capital - Net 64,215 57,572
--------- ---------

TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 122,792 $ 125,152
========= =========
</TABLE>

The accompanying notes are an integral part of the financial statements.

F-4
<PAGE> 118
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per Unit)

<TABLE>
<CAPTION>
For the Years Ended December 31,
---------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
REVENUES:
Oil revenue $ 19,534 $ 17,240 $ 15,470
Gas revenue 28,618 23,770 26,026
Pipeline, facilities and other 2,492 2,444 2,403
Interest 422 326 583
-------- -------- --------
51,066 43,780 44,482
-------- -------- --------

EXPENSES:
Production operating 11,511 11,298 12,177
Facilities operating 726 794 730
General and administrative 4,540 5,580 5,630
Depreciation, depletion and amortization 13,500 15,827 18,168
Impairment of oil and gas properties 10,943 7,345
Interest 3,878 4,245 3,839
Litigation settlement 230 386 3,370
-------- -------- --------
34,385 49,073 51,259
-------- -------- --------

OTHER INCOME (EXPENSE):
Equity in earnings (loss) of HCRC 1,768 (2,273) (1,499)
Minority interest in net income of affiliates (2,723) (1,465) (1,822)
Other 5
-------- -------- --------
(955) (3,738) (3,316)
-------- -------- --------

NET INCOME (LOSS) 15,726 (9,031) (10,093)

CLASS C UNIT DISTRIBUTIONS ($1.00 PER UNIT) 664
-------- -------- --------

NET INCOME (LOSS) ATTRIBUTABLE TO
GENERAL PARTNER, CLASS A AND
CLASS B LIMITED PARTNERS $ 15,062 $ (9,031) $(10,093)
======== ======== ========

ALLOCATION OF NET INCOME (LOSS):

General partner $ 2,569 $ 1,289 $ 1,631
======== ======== ========
Class A and Class B Limited partners $ 12,493 $(10,320) $(11,724)
======== ======== ========
Per Class A Unit and Class B Unit $ 1.34 $ (1.07) $ (1.20)
======== ======== ========

Weighted average Class A Units and Class B
Units and equivalent Units outstanding 9,292 9,683 9,807
======== ======== ========

</TABLE>

The accompanying notes are an integral part of the financial statements.

F-5
<PAGE> 119

HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands except Units)

<TABLE>
<CAPTION>
General Class A Class B Class C Treasury
Partner Units Units Units Units
------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1993 $ 4,872 $ 95,956 $ 1,662 $(3,914)
Increase in Treasury Units
(26)
Syndication costs (34)
Distributions (2,452) (7,052) (116)
Net income (loss) 1,631 (11,528) (196)
------- -------- ------- -------

BALANCE, DECEMBER 31, 1994 4,051 77,342 1,350 (3,940)
Increase in Treasury Units
(2,145)
Syndication costs (63)
Distributions (2,359) (7,517) (116)
Net income (loss) 1,289 (10,148) (172)
------- -------- ------- -------

BALANCE, DECEMBER 31, 1995 2,981 59,614 1,062 (6,085)
Increase in Treasury
Units (894)
Syndication costs (12)
Issuance of Class C Units (5,146) $5,146
Distributions (2,243) (5,270) (664)
Net income 2,569 12,301 192 664
------- -------- ------- ------ -------

BALANCE, DECEMBER 31, 1996 $ 3,307 $ 61,487 $ 1,254 $5,146 $(6,979)
======= ======== ======= ====== =======
</TABLE>

The accompanying notes are an integral part of the financial statements.

F-6
<PAGE> 120
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

<TABLE>
<CAPTION>
For the Years Ended December 31,
----------------------------------
1996 1995 1994
-------- -------- ----------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) $ 15,726 $ (9,031) $(10,093)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion, amortization
and impairment 13,500 26,770 25,513
Depreciation charged to affiliates 265 256 348
Amortization of deferred loan costs and 167 201 260
other assets
Noncash interest expense 219 289 394
Minority interest in net income 2,723 1,465 1,822
Take-or-pay recoupment (376) (571) (313)
Equity in (earnings) loss of HCRC (1,768) 2,273 1,499
Undistributed (earnings) loss of (187) (886) 158
affiliates
Changes in operating assets and liabilities
provided (used) cash net of noncash activity:
Oil and gas revenues receivable (2,638) (547) 3,341
Trade receivables (1,647) 182 2,757
Due from affiliates 2,808 (1,161) (1,529)
Prepaid expenses and other current 163 261 3,590
assets
Accounts payable and accrued (2,159) (1,052) (6,172)
liabilities
Due to affiliates (373)
-------- -------- --------
Net cash provided by operating
activities 26,423 18,449 21,575
-------- -------- --------

INVESTING ACTIVITIES:
Additions to property, plant and equipment (3,148) (2,727) (3,657)
Exploration and development costs incurred (9,467) (8,404) (9,978)
Proceeds from sales of property, plant and 5,294 394 2,599
equipment

Investment in affiliates (449)
Refinance of Spraberry investment (4,715)
Other investing activities (25)
-------- -------- --------
Net cash used in investing
activities (12,485) (10,737) (11,061)
-------- -------- --------

FINANCING ACTIVITIES:
Payments of long-term debt (11,373) (7,379) (12,375)
Proceeds from long-term debt 9,000 15,000 4,300
Distributions paid (8,176) (10,020) (9,547)
Distributions paid by consolidated affiliates
to minority interest (2,429) (1,346) (2,245)
Payment of contract settlement (305) (1,336) (1,343)
Other financing activities (92) (63) (34)
-------- -------- --------
Net cash used in financing
activities (13,375) (5,144) (21,244)
------- ------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 563 2,568 (10,730)

CASH AND CASH EQUIVALENTS:

BEGINNING OF YEAR 4,977 2,409 13,139
-------- -------- --------

END OF YEAR $ 5,540 $ 4,977 $ 2,409
======== ======== ========
</TABLE>

The accompanying notes are an integral part of the financial statements.

F-7
<PAGE> 121

HALLWOOD ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Hallwood Energy Partners, L.P. ("HEP" or the "Partnership") is a
publicly traded Delaware limited partnership engaged in the production, sale and
transportation of oil and gas and in the acquisition, exploration, development
and operation of oil and gas properties. The Partnership's properties are
primarily located in the Greater Permian Region of Texas and Southeast New
Mexico, the Gulf Coast Region of Louisiana and Texas, and the Rocky Mountain
Region. The principal objectives of HEP are to maintain or expand its reserve
base and production and to provide cash distributions to holders of its units
representing limited partner interests ("Units"). HEPGP Ltd. became the
general partner of HEP on November 26, 1996 after HEP's former general partner,
Hallwood Energy Corporation ("HEC"), merged into The Hallwood Group Incorporated
("Hallwood Group"). HEPGP Ltd. is a limited partnership of which Hallwood Group
is the limited partner and Hallwood G.P., Inc. ("Hallwood G.P."), a wholly owned
subsidiary of Hallwood Group, is the general partner. HEP commenced operations
in August 1985 after completing an exchange offer in which HEP acquired oil and
gas properties and operations from HEC, 24 oil and gas limited partnerships of
which HEC was the general partner, and certain working interest owners that had
participated in wells with HEC and the limited partnerships.

The activities of HEP are conducted through HEP Operating Partners, L.P.
("HEPO") and EDP Operating, Ltd. ("EDPO"). HEP is the sole limited partner and
HEPGP Ltd. is the sole general partner of HEPO and EDPO. Solely for purposes
of simplicity herein, unless otherwise indicated, all references to HEP in
connection with the ownership, exploration, development or production of oil
and gas properties include HEPO and EDPO.

ACCOUNTING POLICIES

CONSOLIDATION

HEP fully consolidates entities in which it owns a greater than 50% equity
interest and reflects a minority interest in the consolidated financial
statements. HEP accounts for its interest in 50% or less owned affiliated oil
and gas partnerships and limited liability companies using the proportionate
consolidation method of accounting. HEP's investment in approximately 46% of
the common stock of its affiliate, Hallwood Consolidated Resources Corporation
("HCRC"), is accounted for under the equity method.

The accompanying financial statements include the activities of HEP, its
subsidiaries, Hallwood Petroleum, Inc. ("HPI") and Hallwood Oil and Gas, Inc.
("Hallwood Oil") and majority owned affiliates, the May Limited Partnerships
1983-1, 1983-2, 1983-3, 1984-1, 1984-2, 1984-3 ("Mays").

DERIVATIVES

HEP has entered into numerous financial contracts to hedge the price of its oil
and gas. The purpose of the hedges is to provide protection against price
drops and to provide a measure of stability in the volatile environment of oil
and gas spot pricing. The amounts received or paid upon settlement of these
contracts are recognized as oil or gas revenue at the time the hedged volumes
are sold.

GAS BALANCING

HEP uses the sales method for recording its gas balancing. Under this method,
HEP recognizes revenue on all of its sales of production, and any
over-production or under-production is recovered at a future date.

F-8
<PAGE> 122
As of December 31, 1996, HEP had a net over-produced position of 166,000 mcf
($372,000 valued at average annual natural gas prices). The general partner
believes that this imbalance can be made up from or repaid by production on
existing wells or from wells which will be drilled as offsets to existing wells
and that this imbalance will not have a material effect on HEP's results of
operations, liquidity and capital resources. HEP's oil and gas reserves as of
December 31, 1996 have been decreased by 166,000 mcf in order to reflect HEP's
gas balancing position.

ALLOCATIONS

Partnership costs and revenues are allocated to Unitholders and the General
Partner pursuant to the Partnership Agreement as set forth below.

<TABLE>
<CAPTION>
Unitholders General Partner
----------- ---------------
<S> <C> <C>
Property Costs and Revenues
Initial acquisition costs -
Acreage other than 100% 0%
exploratory
Exploratory acreage 98% 2%
Producing wells -
Costs and revenues 98% 2%
Development wells (1) -
Costs through completion 100% 0%
All other costs and revenues 95% 5%
Exploratory wells (1) -
Costs through completion 90% 10%
All other costs and revenues 75% 25%
All other costs and revenues 98% 2%
</TABLE>

(1) These percentages are for wells drilled under the EDPO
partnership agreement. The majority of wells drilled under
the HEPO partnership agreement share costs through completion
in a ratio of 9.34% to the General Partner and 90.66% to the
Unitholders and share all other costs and revenues in a ratio
of 20.37% to the General Partner and 79.63% to the
Unitholders.

PROPERTY, PLANT AND EQUIPMENT

HEP follows the full cost method of accounting whereby all costs related to the
acquisition of oil and gas properties are capitalized in a single cost center
("full cost pool") and are amortized over the productive life of the underlying
proved reserves using the units of production method. Proceeds from property
sales are generally credited to the full cost pool.

Capitalized costs of oil and gas properties may not exceed an amount equal to
the present value, discounted at 10%, of estimated future net revenues from
proved oil and gas reserves plus the cost, or estimated fair market value, if
lower, of unproved properties. If capitalized costs exceed this ceiling, an
impairment is recognized. The standardized measure of discounted future net
cash flows is computed by applying current prices of oil and gas to estimated
future production of proved oil and gas reserves as of year end, less estimated
future expenditures to be incurred in developing and producing the proved
reserves assuming continuation of existing economic conditions.

HEP does not accrue costs for future site restoration, dismantlement and
abandonment costs related to proved oil and gas properties because the
Partnership estimates that such costs will be offset by the salvage value of
the equipment sold upon abandonment of such properties. The Partnership's
estimates are based upon its historical experience and upon review of current
properties and restoration obligations.

Unproved properties are withheld from the amortization base until such time as
they are either developed or abandoned. The properties are evaluated
periodically for impairment.

F-9
<PAGE> 123
During 1996, HEP adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets
to be Disposed Of" ("SFAS 121"). SFAS 121 provides the standards for
accounting for the impairment of various long-lived assets. Substantially all
of HEP's long-lived assets consist of oil and gas properties which are
evaluated for impairment as described above. Therefore, the adoption of SFAS
121 did not have a material effect on the financial position or results of
operations of HEP.

DEFERRED LIABILITY

The deferred liability as of December 31, 1996 and 1995 consists primarily of
HEP's share of the unrecouped portion of a 1989 take-or-pay settlement, which
is recoupable in gas volumes.

DISTRIBUTIONS

HEP paid a $.13 per Class A Unit and a $.25 per Class C Unit distribution on
February 14, 1997 to Unitholders of record on December 31, 1996. This amount
and the general partner distribution were accrued as of year end. At December
31, 1996 and 1995, distributions payable of $1,996,000 and $2,477,000,
respectively were included in accounts payable and accrued liabilities. HEP
declared distributions of $.52 per Class A Unit and $1.00 per Class C Unit for
1996 and $.80 per Class A and Class B Unit for 1995.

INCOME TAXES

No provision for federal income taxes is included in HEP's financial statements
because, as a partnership, it is not subject to federal income tax and the tax
effect of its activities accrues to the partners. In certain circumstances,
partnerships may be held to be associations taxable as corporations. The
Internal Revenue Service has issued regulations specifying circumstances under
current law when such a finding may be made, and management has obtained an
opinion of counsel based on those regulations that HEP is not an association
taxable as a corporation. A finding that HEP is an association taxable as a
corporation could have a material adverse effect on the financial position,
cash flows and results of operations of HEP.

As a result of the differences in the accounting treatment of certain items for
income tax purposes as opposed to financial reporting purposes, primarily
depreciation, depletion and amortization of oil and gas properties and the
recognition of intangible drilling costs as an expense or capital item, the
income tax basis of oil and gas properties differs from the basis used for
financial reporting purposes. At December 31, 1996 and 1995, the income tax
bases of the Partnership's oil and gas properties were approximately
$122,000,000 and $129,000,000, respectively.

CASH AND CASH EQUIVALENTS

All highly liquid investments purchased with an original maturity of three
months or less are considered to be cash equivalents.

COMPUTATION OF NET INCOME PER UNIT

Net income per Class A and Class B Unit is computed by dividing net income
attributable to the Class A and Class B limited partners' interest (net income
excluding income attributable to the general partner and Class C Units) by the
weighted average number of Class A Units, Class B Units and equivalent Class A
and Class B Units outstanding. The options to acquire Class A Units described
in Note 9 have been considered to be Unit equivalents since June 1, 1996
because the market price of the Class A Units has exceeded the exercise price
of the options since that date. The number of equivalent Units was computed
using the treasury stock method which assumes that the increase in the number
of Units is reduced by the number of Units which could have been repurchased by
the Partnership with the proceeds from the exercise of the options (which were
assumed to have been made at the average market price of the Class A Units
during the reporting period). All Unit and per Unit information has been
restated to reflect the issuance of Class A Units in connection with a lawsuit
settlement further described in Note 12.

F-10
<PAGE> 124
At December 31, 1996 and 1995, HEP owned approximately 46% and 40%,
respectively, of the outstanding common stock of HCRC, which owns approximately
19% of HEP's Class A Units; consequently, HEP had an interest in 899,305 and
784,095 of its own Units as of December 31, 1996 and 1995, respectively. These
Units are treated as treasury Units in the accompanying financial statements.

USE OF ESTIMATES

The preparation of the financial statements for the Partnership in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these estimates.

SIGNIFICANT CUSTOMERS

Although the Partnership sells the majority of its oil and gas production to a
few purchasers, there are numerous other purchasers in the area in which HEP
sells its production; therefore, the loss of its significant customers would
not adversely affect HEP's operations. For the years ended December 31, 1996,
1995 and 1994, purchases by the following companies exceeded 10% of the total
oil and gas revenues of the Partnership:

<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Conoco Inc. 28% 30% 23%
Marathon Petroleum Company 11% 14% 12%
</TABLE>

ENVIRONMENTAL CONCERNS

HEP is continually taking actions it believes are necessary in its operations
to ensure conformity with applicable federal, state and local environmental
regulations. As of December 31, 1996, HEP has not been fined or cited for any
environmental violations which would have a material adverse effect upon
capital expenditures, earnings or the competitive position of HEP in the oil
and gas industry.

RECLASSIFICATIONS

Certain reclassifications have been made to prior years' amounts to conform to
the classifications used in the current year.

F-11
<PAGE> 125
NOTE 2 - OIL AND GAS PROPERTIES

The following table summarizes certain cost information related to HEP's oil
and gas activities:

<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1996 1995 1994
-------- ------- --------
(In thousands)
<S> <C> <C> <C>
Property acquisition costs:
Proved $ 2,321 $ 2,727 $ 3,724
Unproved 560 793 183
Development costs 9,587 11,880 4,995
Exploration costs 831 2,368 4,983
------- ------- -------
Total $13,299 $17,768 $13,885
======= ======= =======
</TABLE>

Depreciation, depletion, amortization and impairment expense related to proved
oil and gas properties per equivalent barrel of production for the years ended
December 31, 1996, 1995 and 1994, was $4.35, $7.21 and $5.79, respectively.

At December 31, unproved properties consisted of the following:

<TABLE>
<CAPTION>
1996 1995
------ ------
(In thousand)
<S> <C> <C>
Texas $1,062 $227
South Louisiana 11 86
Utah 137
Other 171 234
------ ----
$1,244 $684
====== ====
</TABLE>

NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES

1996

On July 1, 1996, HEP and HCRC completed a transaction involving the acquisition
from Fuel Resources Development Co., a wholly owned subsidiary of Public
Service Company of Colorado, and other interest owners of their interests in 38
coal bed methane wells located in La Plata County, Colorado and Rio Arriba
County, New Mexico. Thirty-four of the wells, estimated to have reserves of 53
Bcf, were assigned to 44 Canyon LLC ("44 Canyon"), a special purpose entity
owned by a large east coast financial institution. The wells qualify for tax
credits under Section 29 of the Internal Revenue Code. HPI manages and
operates the properties on behalf of 44 Canyon. The $28.4 million purchase
price was funded by 44 Canyon through the sale of a volumetric production
payment to an affiliate of Enron Capital & Trade Resources Corp., a subsidiary
of Enron Corp., the sale of a subordinated production payment and certain other
property interests for $3.45 million to an affiliate of HEP and HCRC, and
additional cash contributed by the owners of 44 Canyon. The affiliate of HEP
and HCRC which purchased the subordinated production payment and other property
interests is owned equally by HEP and HCRC. The interests in the four wells
in Rio Arriba County were acquired directly by HEP and HCRC.

1995

During 1995, HEP had no individually significant property acquisitions or
sales.

F-12
<PAGE> 126
1994

During the second quarter of 1994, HEP and HCRC formed a limited partnership
with a third party for the purpose of producing natural gas qualified for the
Section 29 tax credit under the Internal Revenue Code. A limited liability
company owned by HEP and HCRC is the general partner of the partnership. In
1994, HEP and HCRC sold a term working interest in certain wells in San Juan
County, New Mexico to the limited partnership. In November 1996, HEP and HCRC
sold to the limited partnership their 80% reversionary interest in the
properties owned by the limited partnership. As consideration for the sale,
HEP and HCRC received a production payment, an increase in incentive payments
and a 90% springing reversionary interest in the properties.

In the 1994 transaction, HEP and HCRC received a cash payment totaling
$3,400,000. HEP recorded its $1,870,000 share of the cash payment received as
a credit to oil and gas properties in the accompanying financial statements.
As a result of the 1994 and 1996 transactions, HEP and HCRC receive 97% of the
cash flow from production from the wells sold until 22.3 Bcf are produced from
the wells (from November 1, 1996) and 80% of the cash flow until 31 Bcf are
produced. HEP and HCRC also receive quarterly cash incentive payments equal
to 34% of the Section 29 tax credit generated from the production from the
wells until 10.3 Bcf are produced from the wells (from November 1, 1996), and
55% thereafter. HEP and HCRC share in all proceeds 55% and 45%, respectively.

NOTE 4 - DERIVATIVES

HEP has entered into numerous financial contracts to hedge the price of its oil
and gas. HEP does not use these hedges for trading purposes, but rather for
the purpose of providing a protection against price drops and to provide a
measure of stability in the volatile environment of oil and gas spot pricing.
The amounts received or paid upon settlement of these contracts is recognized
as oil or gas revenue at the time the hedged volumes are sold.

The financial contracts used by HEP to hedge the price of its oil and gas
production are swaps, collars and participating hedges. Under the swap
contracts, HEP sells its oil and gas production at spot market prices and
receives or makes payments based on the differential between the contract price
and a floating price which is based on spot market indices.

The following table provides a summary of HEP's financial contracts:

<TABLE>
<CAPTION>
Oil
-----------------------------------------------
Quantity of Production
Period Hedged Contract Floor Price
---------- ---------------------- --------------------
(Bbl) (per Bbl)
<S> <C> <C>
1994 361,000 $17.93
1995 380,000 17.41
1996 300,000 18.33
1997 346,000 17.78
1998 103,000 15.38
1999 16,000 15.88
</TABLE>

Certain of HEP's financial contracts for oil are participating hedges whereby
HEP will receive the contract price if the posted futures price is lower than
the contract price, and will receive the contract price plus between 25% and
75% of the difference between the contract price and the posted futures price
if the posted futures price is greater than the contract price. Certain other
of HEP's financial contracts for oil are collar agreements whereby HEP will
receive the contract price if the spot price is lower than the contract price,
the cap price if the spot price is higher than the cap price, and the spot
price if that price is between the contract price and the cap price. The cap
prices range from $17.50 to $19.35.

F-13
<PAGE> 127
<TABLE>
<CAPTION>
Gas
-----------------------------------------------
Quantity of Production
Period Hedged Contract Floor Price
- -------- ---------------------- --------------------
(Mcf) (per Mcf)
<S> <C> <C>
1994 6,461,000 $1.88
1995 6,439,000 1.94
1996 5,479,000 1.94
1997 5,386,000 1.97
1998 4,235,000 2.02
1999 1,860,000 1.86
2000 1,244,000 2.01
</TABLE>

Certain of HEP's financial contracts for gas are collar agreements whereby HEP
will receive the contract price if the spot price is lower than the contract
price, the cap price if the spot price is higher than the cap price, and the
spot price if that price is between the contract price and the cap price. The
cap prices range from $2.78 to $2.93.

In the event of nonperformance by the counterparties to the financial
contracts, HEP is exposed to credit loss, but has no off-balance sheet risk of
accounting loss. The Partnership anticipates that the counterparties will be
able to satisfy their obligations under the contracts because the
counterparties consist of well-established banking and financial institutions
which have been in operation for many years. Certain of HEP's hedges are
secured by the lien on HEP's oil and gas properties which also secures HEP's
Credit Facilities described in Note 6.

NOTE 5 - INVESTMENT IN AFFILIATED CORPORATION

HEP accounts for its approximate 46% interest in HCRC using the equity method
of accounting. The following presents summarized financial information for
HCRC at December 31, 1996, 1995 and 1994:

<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
(In thousands)
<S> <C> <C> <C>
Current assets $10,802 $ 8,312 $ 7,076
Noncurrent assets 67,616 65,627 55,049
Current liabilities 10,849 15,514 6,646
Noncurrent liabilities 24,558 21,790 11,890
Revenue 34,445 25,484 20,644
Net income (loss) 8,160 (4,670) (2,974)
</TABLE>

No other individual entity in which HEP owns an interest comprises in excess of
10% of the revenues, net income or assets of HEP.

HCRC repurchased approximately 99,000 and 26,000 shares of its common stock in
odd lot repurchase offers which were completed January 26, 1996 and May 3,
1996, respectively. HCRC resold 12,965 of these shares to HEP at the price
paid by HCRC for such shares. As a result of these transactions, HEP's
ownership in HCRC increased from 40% to 46% at the end of May 1996.

The following amounts represent HEP's share of the property related costs and
reserve quantities and values of its equity investee HCRC (in thousands):

F-14
<PAGE> 128
CAPITALIZED COSTS RELATING TO OIL AND GAS ACTIVITIES:

<TABLE>
<CAPTION>
As of December 31,
-------------------------------------
1996 1995 1994
---------- --------- --------
<S> <C> <C> <C>
Unproved properties $ 573 $ 230 $ 1,052
Proved properties 113,085 94,925 89,284
Accumulated depreciation, depletion,
amortization and property impairment (89,175) (74,168) (68,587)
-------- -------- --------
Net property $ 24,482 $ 20,987 $ 21,749
======== ======== ========
</TABLE>

COSTS INCURRED IN OIL AND GAS ACTIVITIES:

<TABLE>
<CAPTION>
For the Years Ended December 31,
----------------------------------
1996 1995 1994
------ -------- -------
<S> <C> <C> <C>
Acquisition costs $1,008 $ 4,168 $1,531
Development costs 3,670 2,124 1,531
Exploration costs 382 845 825
------ -------- ------
Total $5,060 $ 7,137 $3,887
====== ======== ======
</TABLE>

RESULTS OF OPERATIONS FOR OIL AND GAS ACTIVITIES:

<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1996 1995 1994
--------- -------- --------
<S> <C> <C> <C>
Oil and gas revenue $ 11,690 $ 7,825 $ 6,522
Production operating expense (3,790) (2,894) (3,008)
Depreciation, depletion, amortization
and property impairment expense (3,257) (2,792) (3,695)
Income tax benefit (expense) 23 (813) 73
-------- -------- --------
Net income (loss) from oil and gas
activities $ 4,666 $ 1,326 $ (108)
======== ======== ========
</TABLE>

PROVED OIL AND GAS RESERVE QUANTITIES:

<TABLE>
<CAPTION>
Gas Oil
--- ---
Mcf Bbl
(unaudited)
<S> <C> <C>
Balance, December 31, 1996 22,786 2,680
====== =====
Balance, December 31, 1995 15,782 2,482
====== =====

Balance, December 31, 1994 14,548 1,771
====== =====
</TABLE>

F-15
<PAGE> 129
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:

<TABLE>
<CAPTION>
(unaudited)
<S> <C>
December 31, 1996 $47,701
=======
December 31, 1995 $25,532
=======
December 31, 1994 $16,466
=======
</TABLE>

NOTE 6 - DEBT

HEP's long-term debt at December 31, 1996 and 1995 consisted of the following:

<TABLE>
<CAPTION>
1996 1995
------ ------
(In thousands)
<S> <C> <C>
Note Purchase Agreement $ 8,571 $12,857

Credit Agreement 26,700 24,700

Other 87
------- -------

Total 35,271 37,644
Less current maturities (5,810) (87)
------- -------
Long-term debt $29,461 $37,557
======= =======
</TABLE>

During the first quarter of 1995, HEP and its lenders amended HEP's Amended and
Restated Credit Agreement ("Credit Agreement") to extend the term date of its
line of credit to May 31, 1997. Under the Credit Agreement and an Amended and
Restated Note Purchase Agreement ("Note Purchase Agreement") (collectively
referred to as the "Credit Facilities"), HEP has a borrowing base of
$48,000,000. HEP had amounts outstanding at December 31, 1996 of $26,700,000
under the Credit Agreement and $8,571,000 under the Note Purchase Agreement.
HEP's borrowing base is further reduced by an outstanding contract settlement
obligation of $2,512,000 (See Note 7); therefore, its unused borrowing base
totaled $10,217,000 at February 28, 1997.

Borrowings under the Note Purchase Agreement bear interest at an annual rate of
11.85%, which is payable quarterly. Annual principal payments of $4,286,000
began April 30, 1992, and the debt is required to be paid in full on April 30,
1998. HEP intends to fund the payment due in April 1997 through additional
borrowings under the Credit Agreement; thus, no portion of HEP's Note Purchase
Agreement is classified as current as of December 31, 1996.

Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus 1.875%, prime plus 1/2% or the Euro-Dollar
rate plus 1.75%. At December 31, 1996 the applicable interest rate was 7.4%.
Interest is payable monthly, and 16 quarterly principal payments of $1,937,000,
as adjusted for the anticipated borrowings to fund the Note Purchase Agreement
payment due in 1997, commence May 31, 1997. HEP intends to extend the maturity
date of its Credit Agreement prior to the commencement of the amortization
period.

The borrowing base for the Credit Facilities is redetermined semiannually in
March and September of each year. The Credit Facilities are secured by a first
lien on approximately 80% of HEP's oil and gas properties as determined by the
lenders. Additionally, aggregate distributions paid by HEP in any 12 month
period are limited to 50% of cash flow from operations before working capital
changes plus distributions received from affiliates.

HEP entered into contracts to hedge its interest rate payments on $10,000,000
of its debt through the end of 1996, $15,000,000 for each of 1997 and 1998 and
$10,000,000 for each of 1999 and 2000. HEP does not use the hedges for

F-16
<PAGE> 130
trading purposes, but rather for the purpose of providing a measure of
predictability for a portion of HEP's interest payments under its debt
agreement which has a floating interest rate. In general, it is HEP's goal to
hedge 50% of the principal amount of its debt for the next two years and 25%
for each year of the remaining term of the debt. HEP has entered into four
hedges, of which one is an interest rate collar pursuant to which it pays a
floor rate of 7.55% and a ceiling rate of 9.85%, and the others are interest
rate swaps with fixed rates ranging from 5.75% to 6.57%. The amounts received
or paid upon settlement of these transactions are recognized as interest
expense at the time the interest payments are due.

At December 31, 1996, HEP's debt maturity schedule is as follows:

<TABLE>
<CAPTION>
(In thousands)
<S> <C>
1997 $ 5,810
1998 12,032
1999 7,746
2000 7,746
2001 1,937
-------
Total $35,271
=======
</TABLE>

NOTE 7 - CONTRACT SETTLEMENT OBLIGATION

In the first quarter of 1989, HEP settled a take-or-pay contract claim on its
Bethany-Longstreet field. In accordance with the settlement, HEP received
$7,623,000 in cash. This amount was recoupable in cash or gas volumes from
April 1992 through March 1996, with a cash balloon payment due during the first
quarter of 1998. A liability has been recorded equal to the present value of
this amount discounted at 10.68%, HEP's estimated borrowing cost at the time of
settlement. HEP also repaid $1,629,000 which represented suspended payments to
the pipeline for previous years in equal monthly installments of $33,937 which
began April 1992 and continued through March 1996. This amount was previously
recorded as an offset to the full cost pool at the time the contract was
initially abrogated by the pipeline. As payment of this obligation was made it
was charged to the full cost pool.

At December 31, 1996, the long-term contract settlement balance consists of a
payment of $2,767,000 due in March 1998, net of unaccreted discount of
$255,000.

NOTE 8 - PARTNERS' CAPITAL

HEP Units that trade on the American Stock Exchange under the symbol "HEP" are
referred to as "Class A Units," and Units that trade under the symbol "HEPC"
are referred to as "Class C Units."

CLASS B SUBORDINATED UNITS

The Class B Units have equal liquidation rights and identical tax allocation
rights and provisions to the Class A Units. However, the Class B Units have
the following subordinated distribution provisions:

1. Distribution rights equal to Class A Units while the Class A Units
receive distributions of $.20 or more per Class A Unit per calendar
quarter.

2. No current distribution right should Class A Units receive
distributions less than $.20 per Class A Unit for any calendar
quarter.

3. An accumulated distribution deficit account is maintained for the
benefit of the Class B Units for any distributions suspended under 2
above. The amount in the deficit account is payable in whole or in
part to the Class B Unitholders in any quarter in which distributions
equal to or greater than $.20 per Class A Unit are made on Class A
Units.

F-17
<PAGE> 131
The Class B Units may be converted into Class A Units on a 1:1 ratio at the
option of the holder or holders thereof. Upon conversion, any amount remaining
unpaid in the accumulated distribution deficit account relating to Class B
Units converted is waived.

The Class B Units vote as a separate class on all matters required or otherwise
brought for a vote of the Unitholders of HEP.

CLASS C UNITS

The Class C Units were issued on January 19, 1996 to Class A Unitholders in the
ratio of one Class C Unit for every 15 Class A Units outstanding. In
connection with the issuance of the Class C Units, HEP transferred $5,146,000
of partners capital from the Class A Unitholders to the Class C Unitholders
based on the initial trading price of the Class C Units.

The Class C Units have a distribution preference of $1.00 per year, payable
quarterly, commencing in the first quarter of 1996. HEP may not declare or
make any cash distributions on the Class A or Class B Units unless all accrued
and unpaid distributions on the Class C Units have been paid.

Class C Units vote as a separate class on all matters submitted to the
unitholders of HEP for a vote.

RIGHTS PLAN

On February 6, 1995 the board of directors of HEC approved the adoption of a
rights plan designed to protect Unitholders in the event of a takeover action
that would otherwise deny them the full value of their investment.

Under the terms of the rights plan, one right was distributed for each Class A
Unit of HEP to holders of record at the close of business on February 17, 1995.
The rights trade with the Class A Units. The rights will become exercisable
only in the event, with certain exceptions, that an acquiring party accumulates
15% or more of HEP's Class A Units, or if a party announces an offer to acquire
30% or more of HEP. The rights will expire on February 6, 2005. In addition,
upon the occurrence of certain events, holders of the rights will be entitled
to purchase, for $24, either HEP Class A Units or shares in an "acquiring
entity," with a market value at that time of $48.

HEP will generally be entitled to redeem the rights at one cent per right at
any time until the tenth day following the acquisition of a 15% position in its
Units.

NOTE 9 - EMPLOYEE INCENTIVE PLANS

Every year beginning in 1992, the Board of Directors of the general partner has
adopted an incentive plan. Each year the Board of Directors determines the
percentage of HEP's interest in the cash flow from certain wells drilled,
recompleted or enhanced during the year allocated to the incentive plan for
that year. The specified percentage was 2.4% for 1996, 1.4% for domestic wells
for 1995 and 1% for domestic wells for 1994. In 1994 and 1995, HEP also had an
international incentive plan and the percentage interest in cash flow for that
plan was 3%. Beginning in 1996, the domestic and international plans were
combined. The specified percentage of cash flow is then allocated among
certain key employees who are participants in the Plan for that year. Each
award under the plan (with regard to domestic properties) represents the right
to receive for five years a portion of the specified share of the cash award,
and the participants are each paid a share of an amount equal to a specified
percentage (80% for 1995 and 1996 and 40% for 1994) of the remaining net
present value of the qualifying wells, and the award for that year terminates.
The expenses attributable to the plans were $148,000 in 1996, $119,000 in 1995
and $88,000 in 1994 and are included in general and administrative expense in
the accompanying financial statements.

On January 31, 1995, the board of directors of HEC approved the adoption of the
Unit Option Plan ("Option Plan") to be used for the motivation and retention of
directors, employees and consultants performing services for HEP. The plan
authorizes the issuance of options to purchase 425,000 Class A Units. Grants
of the total options authorized were made on January 31, 1995, vesting
one-third at that time, an additional one-third on January 31, 1996 and the
remaining one-

F-18
<PAGE> 132
third on January 31, 1997. The exercise price of the options is $5.75, which
was the closing price of the Class A Units on January 30, 1995.

A summary of options granted under the Option Plan as of December 31, 1996 and
1995 and the changes therein during the years then ended on those dates is
presented below:

<TABLE>
<CAPTION>
1996 1995
------ -----
Exercise Exercise
Units Price Units Price
----- ---------- ----- ----------
<S> <C> <C> <C> <C>
Outstanding at beginning of year 425,000 $5.75

Granted 425,000 $5.75
------- ----- ------- -----
Outstanding at end of year 425,000 $5.75 425,000 $5.75
======= ===== ======= =====

Options exercisable at year end 283,330 141,665
======= =======
</TABLE>

The Partnership has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"). Accordingly, no compensation cost has been
recognized for the Option Plan. Had compensation expense for the Option Plan
been determined based on the fair value at the grant date for the options
awarded in 1995 consistent with the provisions of SFAS 123, HEP's net income
(loss) and net income (loss) per Unit would have been reduced to the pro forma
amounts indicated below:

<TABLE>
<CAPTION>
1996 1995
------ ------
<S> <C> <C> <C>
Net income (loss): as reported $15,726,000 $(9,031,000)
pro forma 15,544,000 (9,432,000)

Net income (loss)
per Class A and B Unit: as $1.34 $(1.07)
reported
pro forma 1.32 (1.11)
</TABLE>

The fair value of the Unit options for disclosure purposes was estimated on the
date of the grant using the Binomial Option Pricing Model with the following
assumptions:

<TABLE>
<S> <C>
Expected dividend yield 6%
Expected price volatility 28%
Risk-free interest rate 7.6%
Expected life of options 10 years
</TABLE>

F-19
<PAGE> 133
NOTE 10 - RELATED PARTY TRANSACTIONS

HPI manages and operates certain oil and gas properties on behalf of
independent joint interest owners, HEP and its affiliates. In such capacity,
HPI pays all costs and expenses of operations and distributes all revenues
associated with such properties. HPI had payables to affiliates of HEP of
$159,000 at December 31, 1996 and receivables from affiliates of HEP of
$2,808,000 at December 31, 1995, which represented revenues net of operating
costs and expenses. The intercompany balances are settled monthly.

HPI is reimbursed by HEP for costs and expenses which includes office rent,
salaries and associated overhead for personnel of HPI engaged in the
acquisition and evaluation of oil and gas properties (technical expenditures
which are capitalized as costs of oil and gas properties) and lease operating
and general and administrative expenses necessary to conduct the business of
HEP (nontechnical expenditures which are expensed as general and administrative
or production operating expenses). Reimbursements during 1996, 1995 and 1994
were as follows:

<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
(In thousands)
<S> <C> <C> <C>
Technical $1,249 $1,100 $ 747
Nontechnical 1,110 1,321 1,502
</TABLE>

Included in the nontechnical allocation attributable to HEP's direct interest
for 1996, 1995 and 1994 is approximately $152,000, $156,000 and $159,000,
respectively, of consulting fees under a consulting agreement with Hallwood
Group. Also included in the nontechnical allocation is $309,000, $369,000 and
$363,000 in 1996, 1995 and 1994, respectively, representing costs incurred by
Hallwood Group and its affiliates on behalf of the Partnership.

During the third quarter of 1994, HPI entered into a consulting agreement with
its Chairman of the Board to provide advisory services regarding the activities
of its affiliates. The amount of consulting fees allocated to the Partnership
under this agreement is $125,000 in both 1996 and 1995 and $62,500 in 1994.

NOTE 11 - STATEMENT OF CASH FLOWS

Cash paid during 1996, 1995 and 1994 for interest totaled $3,492,000,
$3,356,000 and $3,185,000, respectively.

NOTE 12 - LITIGATION SETTLEMENTS

In September 1995, the court order approving the settlement in the class action
lawsuit styled In re. Hallwood Energy Partners, L.P. Securities Litigation
became final. As part of the settlement, on September 28, 1995, HEP paid
$2,870,000 in cash (which was recorded as an expense in the December 31, 1994
financial statements as the estimated cost associated with the litigation) and
issued 1,158,696 Class A Units with a market value of $5,330,000 to a nominee
of the class. HCRC subsequently exercised an option to purchase these Units
from the nominee for $5,330,000 in cash. Other defendants contributed an
additional $900,000 in cash to the settlement. The net proceeds of the
settlement were distributed to a class consisting of former owners of limited
partner interests in Energy Development Partners, Ltd. ("EDP") who exchanged
their units in that entity for Units of HEP pursuant to the merger of EDP and
HEP on May 9, 1990 (the "Transaction").

F-20
<PAGE> 134
Upon issuance, these Class A Units were treated, for financial statement
purposes, as additional Class A Units issued in connection with the
Transaction, which was accounted for as a reorganization of entities under
common control, in a manner similar to a pooling of interest, and have been
reflected as outstanding Class A Units since May 9, 1990, the date of the
Transaction. As a result of the settlement, the number of Units outstanding
and the net income (loss) per Class A Unit and Class B Unit have been
retroactively restated for all periods subsequent to the Transaction date.

NOTE 13 - LEGAL PROCEEDINGS

In June 1996, HEP and the other parties to the lawsuits styled Lamson Petroleum
Corporation v. Hallwood Petroleum, Inc. et al. settled the lawsuits. The
plaintiffs in the lawsuits claimed they had valid leases covering streets and
roads in the units of the A. L. Boudreaux #1 well, G. S. Boudreaux #1 well,
Paul Castille #1 well, Evangeline Shrine Club #1 well and Duhon #1 well, which
represented approximately .4% to 2.3% of HEP's interest in these properties,
and they were entitled to a portion of the production from the wells dating
from February 1990. In the settlement, HEP and the plaintiffs agreed to
cross-convey interests in certain leases to one another, and HEP agreed to pay
the plaintiffs $728,000. HEP has not recognized revenue attributable to the
contested leases since January 1993. These revenues plus accrued interest,
totaling $506,000, had been placed in escrow pending the resolution of the
lawsuits. The excess of the cash paid over the escrowed amounts, is reflected
as litigation settlement expense in the accompanying financial statements. The
cross-conveyance of the interests in the leases resulted in a decrease in HEP's
reserves of $374,000 in future net revenues, discounted at 10%.

The Partnership is involved in other legal proceedings and claims which have
arisen in the ordinary course of its business and have not been finally
adjudicated. The Partnership believes that its liability, if any, as a result
of such proceedings and claims will not materially affect its financial
condition, cash flows or operations.

NOTE 14 - COMMITMENTS

HPI leases office facilities under operating leases which expire in 1999. Rent
expense under these leases is allocated to HEP and its affiliates. Remaining
commitments under these leases mature as follows:

<TABLE>
<CAPTION>
Year Ending
December 31, Annual Rentals
------------ --------------
(in thousands)
<S> <C>
1997 $ 632
1998 632
1999 316
------
$1,580
======
</TABLE>

Rent expense allocated to HEP was $304,000, $299,000, and $291,000 for the
years ended December 31, 1996, 1995 and 1994, respectively.

NOTE 15 - ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments
is made in accordance with the requirements of SFAS No. 107, "Disclosures about
Fair Value of Financial Instruments." The estimated fair value amounts have
been determined by the Partnership, using available market information and
appropriate valuation methodologies. However, considerable judgment is
necessarily required in interpreting market data to develop the estimates of
fair value. Accordingly, the estimates presented herein are not necessarily
indicative of the amounts that the Partnership could realize in a current
market exchange. The use of different market assumptions and/or estimation
methodologies may have a material effect on the estimated fair value amounts.

F-21
<PAGE> 135
<TABLE>
<CAPTION>
December 31, 1996
-----------------------------
Carrying Estimated Fair
Amount Value
-------- --------------
(In thousands)
<S> <C> <C>
LIABILITIES:
Interest rate hedge contracts $ -0- $ 250
Oil and gas hedge contracts -0- 20,000
Current portion of long-term debt 5,810 5,810
Long-term debt 29,461 29,716
Contract settlement 2,512 2,524
</TABLE>

The estimated fair value of the interest rate hedge contracts is computed by
multiplying the difference between the year end interest rate and the contract
interest rate by the amounts under contract. This amount has been discounted
using an interest rate that could be available to the Partnership.

The estimated fair value of the oil and gas hedge contracts is determined by
multiplying the difference between year end oil and gas prices and the hedge
contract prices by the quantities under contract. This amount has been
discounted using an interest rate that could be available to the Partnership.

The current portion of long-term debt is carried in the accompanying balance
sheets at an amount which is a reasonable estimate of its fair value.

The estimated fair value of long-term debt and contract settlement is
determined using interest rates that could be available to the Partnership for
similar instruments with similar terms.

The fair value estimates presented herein are based on pertinent information
available to management as of December 31, 1996. Although management is not
aware of any factors that would significantly affect the estimated fair value
amounts, such amounts have not been comprehensively revalued for purposes of
these financial statements since that date, and current estimates of fair value
may differ significantly from the amounts presented herein.

F-22
<PAGE> 136
HALLWOOD ENERGY PARTNERS, L.P.
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
DECEMBER 31, 1996
(Unaudited)

The following reserve quantity and future net cash flow information for HEP
represents proved reserves which are located in the United States. The
reserves have been estimated by HPI's in-house engineers. 80% of these
reserves has been reviewed by independent petroleum engineers. The
determination of oil and gas reserves is based on estimates which are highly
complex and interpretive. The estimates are subject to continuing change as
additional information becomes available.

The standardized measure of discounted future net cash flows provides a
comparison of HEP's proved oil and gas reserves from year to year. No
consideration has been given to future income taxes for HEP as it is not a
taxpaying entity. Under the guidelines set forth by the Securities and
Exchange Commission (SEC), the calculation is performed using year end prices
unless contracts provide otherwise. At December 31, 1996, oil and gas prices
averaged $24.18 per Bbl of oil and $3.76 per mcf of gas for HEP, including its
indirect interests in affiliated partnerships and the Mays. Future production
costs are based on year end costs and include severance taxes. The present
value of future cash inflows is based on a 10% discount rate. The reserve
calculations using these December 31, 1996 prices result in 7.5 million Bbls of
oil, and 88.5 Bcf of natural gas and a standardized measure of $206,000,000.
The Mays are included on a consolidated basis, and 63,000 Bbls of oil and 1.7
Bcf of gas, representing a discounted present value of $6,800,000 are
attributable to the minority ownership of these entities. This standardized
measure is not necessarily representative of the market value of HEP's
properties. The portion of the reserves attributable to the General Partner's
interest totaled 300,000 Bbls of oil and 6 Bcf of gas with a standardized
measure of $16,000,000 at December 31, 1996.

HEP's standardized measure of future net cash flows has been decreased by
$20,000,000 at December 31, 1996 for the effects of its hedge contracts. This
amount represents the difference between year end oil and gas prices and the
hedge contract prices multiplied by the quantities subject to contract,
discounted at 10%.

F-23
<PAGE> 137
HALLWOOD ENERGY PARTNERS, L.P.
RESERVE QUANTITIES
(In thousands)
(Unaudited)

<TABLE>
<CAPTION>
Gas Oil
------- -------
Mcf Bbls
<S> <C> <C>
PROVED RESERVES:
Balance, December 31, 1993 91,607 5,453

Extensions and discoveries 5,985 1,052
Revisions of previous estimates 1,318 1,113
Sales of reserves in place (816) (84)
Purchase of reserves in place 699 143
Production (13,208) (939)
------- -------

Balance, December 31, 1994 85,585 6,738

Extensions and discoveries 5,997 1,902
Revisions of previous estimates 4,248 464
Sales of reserves in place (45) (41)
Purchase of reserves in place 362 28
Production (13,035) (993)
------- -------

Balance, December 31, 1995 83,112 8,098

Extensions and discoveries 1,683 484
Revisions of previous estimates 10,552 385
Sales of reserves in place (3,369) (481)
Purchase of reserves in place 9,350 17
Production (12,786) (972)
------- -------

Balance, December 31, 1996 88,542 7,531
======= =======

PROVED DEVELOPED RESERVES:
Balance, December 31, 1994 79,699 6,166
======= =======
Balance, December 31, 1995 77,378 7,444
======= =======
Balance, December 31, 1996 85,848 7,056
======= =======
</TABLE>

F-24
<PAGE> 138
HALLWOOD ENERGY PARTNERS, L. P.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)

<TABLE>
<CAPTION>
December 31,
---------------------------------
1996 1995 1994
------ -------- --------
<S> <C> <C> <C>
Future cash flows $509,000 $317,000 $262,000
Future production and development costs (175,000) (130,000) (109,000)
-------- -------- --------
Future net cash flows before discount 334,000 187,000 153,000

10% discount to present value (128,000) (63,000) (49,000)
-------- -------- --------
Standardized measure of discounted future net
cash flows $206,000 $124,000 $104,000
======== ======== ========
</TABLE>

F-25
<PAGE> 139
HALLWOOD ENERGY PARTNERS, L. P.
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)

<TABLE>
<CAPTION>
For the Years Ended December 31,
------------------------------------
1996 1995 1994
--------- -------- --------
<S> <C> <C> <C>
Standardized measure of discounted future net
cash flows at beginning of year $124,000 $104,000 $121,000
Sales of oil and gas produced, net of
production costs (35,915) (29,712) (29,319)

Net changes in prices and production costs 75,085 17,015 (19,175)
Extensions and discoveries, net of future
production and development costs 7,144 16,836 10,537

Changes in estimated future development costs (7,492) (11,868) (5,614)
Development costs incurred 9,195 11,880 4,995

Revisions of previous quantity estimates 20,032 6,817 6,852
Purchases of reserves in place 14,721 513 1,334

Sales of reserves in place (9,742) (281) (1,131)
Accretion of discount 12,400 10,400 12,100

Changes in production rates and other (3,428) (1,600) 2,421
-------- -------- --------
Standardized measure of discounted future net
cash flows at end of year $206,000 $124,000 $104,000
======== ======== ========
</TABLE>

F-26
<PAGE> 140
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In thousands)

<TABLE>
<CAPTION>
September 30,
1997
-------------
<S> <C>
CURRENT ASSETS
Cash and cash equivalents $ 1,769
Accounts receivable:
Oil and gas revenues 7,429
Trade 4,812
Due from affiliates 996
Prepaid expenses and other current assets 1,959
---------
Total 16,965
---------

PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method):
Proved mineral interests 620,049
Unproved mineral interests - domestic 1,710
Furniture, fixtures and other 3,498
---------
Total 625,257

Less accumulated depreciation, depletion,
amortization and property impairment (532,758)
---------
Total 92,499
---------

OTHER ASSETS
Investment in common stock of HCRC 15,084
Deferred expenses and other assets 102
---------
Total 15,186
---------

TOTAL ASSETS $ 124,650
=========
</TABLE>

(Continued on the following page)

F-27
<PAGE> 141
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In thousands except Units)

<TABLE>
<CAPTION>
September 30,
1997
-------------
<S> <C>
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 16,767
Net working capital deficit of affiliate 383
Current portion of contract settlement 2,690
---------
Total 19,840
---------

NONCURRENT LIABILITIES
Long-term debt 31,986
Deferred liability 1,209
---------
Total 33,195
---------

Total liabilities 53,035
---------

MINORITY INTEREST IN AFFILIATES 3,174
---------

PARTNERS' CAPITAL
Class A Units - 9,977,254 Units issued, 9,077,949
outstanding 65,374
Class B Subordinated Units - 143,773 Units issued
and outstanding 1,379
Class C Units - 664,063 Units issued and outstanding 5,146
General Partner 3,521
Treasury Units - 899,305 Units (6,979)
---------
Partners' capital - net 68,441
---------

TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 124,650
=========
</TABLE>

The accompanying notes are an integral part
of the financial statements.

F-28
<PAGE> 142
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Unit data)

<TABLE>
<CAPTION>
For the Nine Months Ended
September 30,
------------------------
1997 1996
-------- ------------
<S> <C> <C>
REVENUES:
Oil revenue $ 11,157 $ 14,600
Gas revenue 19,073 21,322
Pipeline, facilities and other 2,072 2,039
Interest 328 331
-------- --------
32,630 38,292
-------- --------

EXPENSES:
Production operating 8,207 8,379
Facilities operating 560 551
General and administrative 3,250 3,133
Depreciation, depletion and amortization 8,657 10,554
Interest 2,315 3,047
-------- --------
22,989 25,664
-------- --------

OTHER INCOME (EXPENSE):
Equity in earnings of HCRC 1,384 1,227
Minority interest in net income of affiliates (1,341) (2,092)
Litigation settlement 240 (230)
-------- --------
283 (1,095)
-------- --------

NET INCOME 9,924 11,533

CLASS C UNIT DISTRIBUTIONS ($.75 PER UNIT) 498 498
-------- --------

NET INCOME ATTRIBUTABLE TO GENERAL PARTNER,
CLASS A AND CLASS B LIMITED PARTNERS $ 9,426 $ 11,035
======== ========

ALLOCATION OF NET INCOME:
General partner $ 1,408 $ 1,923
======== ========
Class A and Class B limited partners $ 8,018 $ 9,112
======== ========
Per Class A Unit and Class B Unit $ .86 $ .99
======== ========

Weighted average Class A Units and Class B Units
and equivalent Units outstanding 9,348 9,246
======== ========
</TABLE>

The accompanying notes are an integral part
of the financial statements.

F-29
<PAGE> 143
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

<TABLE>
<CAPTION>
For the Nine Months Ended
September 30,
-------------------------
1997 1996
-------- ----------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income $ 9,924 $ 11,533
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 8,657 10,554
Depreciation charged to affiliates 165 195
Amortization of deferred loan costs and other assets 61 122
Noncash interest expense 178 163
Equity in earnings of HCRC (1,384) (1,227)
Minority interest in net income of affiliates 1,341 2,092
Undistributed earnings of affiliates 73 (558)
Recoupment of take-or-pay liability (97) (331)
Changes in operating assets and liabilities provided (used) cash net
of noncash activity:
Oil and gas revenues receivable 1,976 (146)
Trade receivables (305) (1,243)
Due from affiliates (996) 2,287
Prepaid expenses and other current assets (1,031) (339)
Accounts payable and accrued liabilities 1,488 (1,220)
Due to affiliates (1,772) 861
-------- --------
Net cash provided by operating activities 18,278 22,748
-------- --------

INVESTING ACTIVITIES:
Additions to property, plant and equipment (2,499) (2,667)
Exploration and development costs incurred (9,073) (6,838)
Proceeds from sales of property, plant and equipment 85 5,287
Refinance of Spraberry investment (4,715)
Investment in affiliates (76) (517)
-------- --------
Net cash used in investing activities (11,563) (9,450)
-------- --------

FINANCING ACTIVITIES:
Payments of long-term debt (5,285) (8,373)
Proceeds from long-term debt 2,000 6,000
Distributions paid (5,583) (6,180)
Distributions paid by consolidated affiliates to minority interest (1,508) (1,778)
Payment of contract settlement (305)
Syndication costs and capital contributions (12)
Other financing activities (115) (128)
-------- --------
Net cash used in financing activities (10,486) (10,776)
-------- --------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (3,771) 2,522

CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD 5,540 4,977
-------- --------

END OF PERIOD $ 1,769 $ 7,499
======== ========
</TABLE>

The accompanying notes are an integral part
of the financial statements.

F-30
<PAGE> 144
HALLWOOD ENERGY PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1 - GENERAL

Hallwood Energy Partners, L. P. ("HEP") is a publicly traded Delaware limited
partnership engaged in the development, acquisition and production of oil and
gas properties in the continental United States. HEP's objective is to provide
its partners with an attractive return through a combination of cash
distributions and capital appreciation. To achieve its objective, HEP utilizes
operating cash flow, first, to reinvest in operations to maintain its reserve
base and production; second, to make stable cash distributions to Unitholders;
and third, to grow HEP's reserve base over time. Future growth will be driven
by a combination of development of existing projects, exploration for new
reserves and select acquisitions. The general partner of HEP is HEPGP Ltd.

The activities of HEP are conducted through HEP Operating Partners, L.P.
("HEPO") and EDP Operating, Ltd. ("EDPO"). HEP is the sole limited partner and
HEPGP Ltd. is the sole general partner of HEPO and of EDPO. Solely for
purposes of simplicity herein, unless otherwise indicated, all references to
HEP in connection with the ownership, exploration, development or production of
oil and gas properties include HEPO and EDPO.

The interim financial data are unaudited; however, in the opinion of the
general partner, the interim data include all adjustments, consisting only of
normal recurring adjustments, necessary for a fair presentation of the results
for the interim periods. These financial statements should be read in
conjunction with the financial statements and accompanying notes included
elsewhere in this Prospectus.

ACCOUNTING POLICIES

CONSOLIDATION

HEP fully consolidates entities in which it owns a greater than 50% equity
interest and reflects a minority interest in the consolidated financial
statements. HEP accounts for its interest in 50% or less owned affiliated oil
and gas partnerships and limited liability companies using the proportionate
consolidation method of accounting. HEP's investment in the common stock of
its affiliate, Hallwood Consolidated Resources Corporation ("HCRC"), is
accounted for under the equity method.

The accompanying financial statements include the activities of HEP, its
subsidiaries Hallwood Petroleum, Inc. ("HPI") and Hallwood Oil and Gas, Inc.
("Hallwood Oil"), and majority owned affiliates, the May Limited Partnerships
1983-1, 1983-2, 1983-3, 1984-1, 1984-2, 1984-3 ("Mays").

COMPUTATION OF NET INCOME PER UNIT

Net income per Class A and Class B Unit is computed by dividing net income
attributable to the Class A and Class B limited partners' interest (net income
excluding income attributable to the general partner and Class C Units) by the
weighted average number of Class A Units, Class B Units and equivalent Class A
and Class B Units outstanding. The options to acquire Class A Units, which
were issued during 1995, are considered to be Unit equivalents since January 1,
1997 because the market price of the Class A Units has exceeded the exercise
price of the options since that date. The number of equivalent Units was
computed using the treasury stock method which assumes that the increase in the
number of Units is reduced by the number of Units which could have been
repurchased by the Partnership with the proceeds from the exercise of the
options (which were assumed to have been made at the average market price of
the Class A Units during the reporting period).

F-31
<PAGE> 145

HEP owns approximately 46% of the outstanding common stock of HCRC, while HCRC
owns approximately 19% of HEP's Units. Consequently, HEP had an interest in
899,305 of its own Units at September 30, 1997. These Units are treated as
treasury units in the accompanying financial statements.

During February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128, Earnings per Share ("SFAS 128").
SFAS 128 establishes standards for computing and presenting earnings per share
(EPS), and supersedes APB Opinion No. 15 and its related interpretations. It
replaces the presentation of primary EPS with a presentation of basic EPS,
which excludes dilution, and requires dual presentation of basic and diluted
EPS for all entities with complex capital structures. Diluted EPS is computed
similarly to fully diluted EPS pursuant to Opinion No. 15. SFAS 128 is
effective for periods ending after December 15, 1997, including interim
periods, and will require restatement of all prior period EPS data presented;
earlier application is not permitted.

A comparison of EPS shown in the accompanying financial statements with the pro
forma amounts that would have been determined in accordance with SFAS 128 is as
follows:

<TABLE>
<CAPTION>
For the Nine Months Ended September 30,
---------------------------------------
1997 1996
------ ------
<S> <C> <C>
Primary (Basic):
As reported $.86 $.99
Pro forma $.87 $.99

Fully Diluted (Diluted):
As reported $.86 $.99
Pro forma $.86 $.99
</TABLE>

RECLASSIFICATIONS

Certain reclassifications have been made to the prior period amounts to conform
to the classifications used in the current period.

NOTE 2 - DEBT

During the second quarter of 1997, HEP and its lenders amended and restated
HEP's Second Amended and Restated Credit Agreement (as amended, the "Credit
Agreement") to extend the term date of its line of credit to May 31, 1999.
Under the Credit Agreement and an Amended and Restated Note Purchase Agreement
("Note Purchase Agreement") (collectively referred to as the "Credit
Facilities"), HEP's borrowing base was $46,000,000 at October 31, 1997. HEP
had amounts outstanding at September 30, 1997 of $27,700,000 under the Credit
Agreement and $4,286,000 under the Note Purchase Agreement. HEP's borrowing
base is further reduced by an outstanding contract settlement obligation of
$2,690,000 and borrowings of $2,000,000 made subsequent to September 30, 1997;
therefore, its unused borrowing base totaled $11,324,000 at October 31, 1997.

Borrowings under the Note Purchase Agreement bear interest at an annual rate of
11.85%, which is payable quarterly. Annual principal payments of $4,286,000
began April 30, 1992, and the debt is required to be paid in full on April 30,
1998. HEP intends to fund the payment due in April 1998 through additional
borrowings under the Credit Agreement; thus, no portion of HEP's Note Purchase
Agreement is classified as current as of September 30, 1997.

Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was
7.2% at September 30, 1997. Interest is payable monthly, and quarterly
principal payments of $2,124,000 as adjusted for the $2,000,000 of borrowings
made subsequent to September 30, 1997 as well as the anticipated borrowings to
fund the Note Purchase Agreement payment due in April 1998, commence May 31,
1999.

F-32
<PAGE> 146
The borrowing base for the Credit Facilities is redetermined semiannually. The
Credit Facilities are secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions paid by
HEP in any 12 month period are limited to 50% of cash flow from operations
before working capital changes plus 50% of distributions received from
affiliates, if the principal amount of debt of HEP is 50% or more of the
borrowing base. Aggregate distributions paid by HEP are limited to 65% of cash
flow from operations, plus 65% of distributions received from affiliates if the
principal amount of debt is less than 50% of the borrowing base.

HEP entered into contracts to hedge its interest rate payments on $15,000,000
of its debt for each of 1997 and 1998 and $10,000,000 for each of 1999 and
2000. HEP does not use the hedges for trading purposes, but rather for the
purpose of providing a measure of predictability for a portion of HEP's
interest payments under its debt agreement, which has a floating interest rate.
In general, it is HEP's goal to hedge 50% of the principal amount of its debt
for the next two years and 25% for each year of the remaining term of the debt.
HEP has entered into four hedges, one of which is an interest rate collar
pursuant to which it pays a floor rate of 7.55% and a ceiling rate of 9.85%,
and the others are interest rate swaps with fixed rates ranging from 5.75% to
6.57%. The amounts received or paid upon settlement of these transactions are
recognized as interest expense at the time the interest payments are due.

NOTE 3 - STATEMENTS OF CASH FLOWS

Cash paid for interest during the nine months ended September 30, 1997 and 1996
was $2,077,000 and $2,761,000, respectively.

NOTE 4 - SUBSEQUENT EVENT

In October 1997 the Partnership filed with the Securities and Exchange
Commission a registration statement covering the sale by the Partnership of
newly issued Class C Units. The Partnership intends to use the net proceeds
from the offering to accelerate the drilling of its project inventory and, in
the interim, to repay a portion of its outstanding indebtedness under its
Credit Agreement. A registration statement relating to the Class C Units has
been filed with the Securities and Exchange Commission but has not yet become
effective. The Class C Units may not be sold nor may offers to buy be accepted
prior to the time the registration statement becomes effective. This
information shall not constitute an offer to sell or the solicitation of an
offer to buy nor shall there be any sale of the Class C Units in any State in
which such offer, solicitation or sale would be unlawful prior to registration
or qualification under the securities laws of any such State.

F-33
<PAGE> 147

HEPGP LTD.
BALANCE SHEETS
DECEMBER 31, 1996 AND SEPTEMBER 30, 1997
(Unaudited)
(in thousands)

<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1997 1996
------------- ------------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents ............................. $ 31 $ 182
Due from affiliates ................................... 417 1,056
Accounts receivable ................................... 76 109
Current assets of affiliate ........................... 954 1,128
------ ------
Total ........................................ 1,478 2,475
------ ------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method), net of
accumulated depletion, depreciation and amortization 4,056 4,321
------ ------
OTHER ASSETS
Note receivable from affiliate ........................ 2,000 2,000
Noncurrent assets of affiliate ........................ 924 849
------ ------
Total ........................................ 2,924 2,849
------ ------
TOTAL ASSETS ................................................... $8,458 $9,645
====== ======

CURRENT LIABILITIES
Accounts payable and accrued liabilities .............. $ 62 $ 161
Current portion of long-term debt ..................... 610 1,668
Current liabilities of affiliate ...................... 1,121 1,146
------ ------
Total ........................................ 1,793 2,995
------ ------
NONCURRENT LIABILITIES
Long-term debt ........................................ 693
Long-term liabilities of affiliate .................... 2,047 2,085
------ ------
Total ........................................ 2,047 2,778
------ ------
PARTNERS' CAPITAL
General Partner ....................................... 46 39
Limited Partner ....................................... 4,572 3,833
------ ------
Total ........................................ 4,618 3,872
------ ------

TOTAL LIABILITIES AND PARTNERS' CAPITAL ........................ $8,458 $9,645
====== ======
</TABLE>

F-34
<PAGE> 148

HEPGP LTD.
NOTES TO BALANCE SHEETS
(UNAUDITED)

NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

HEPGP Ltd. ("HEPGP" or the "Partnership") is a Colorado limited partnership
engaged in the development, acquisition and production of oil and gas
properties in the continental United States. HEPGP is the general partner of
Hallwood Energy Partners, L.P. ("HEP"), a publicly traded Delaware limited
partnership. HEPGP conducts substantially all of its operations through HEP.
Hallwood G.P., Inc. is the general partner of HEPGP and The Hallwood Group
Incorporated ("Hallwood Group") is the sole limited partner of HEPGP.

SIGNIFICANT ACCOUNTING POLICIES:

INVESTMENT IN HEP

HEPGP's general partner interest in HEP entitles it to a share of net revenues
derived from HEP's properties ranging from 2% to 25%. HEPGP accounts for its
ownership interest in HEP using the proportionate consolidation method of
accounting whereby HEPGP records its proportionate share of each of HEP's
current assets, current liabilities, noncurrent assets, long-term obligations
and fixed assets in its balance sheets.

CASH AND CASH EQUIVALENTS

All highly liquid investments purchased with an original maturity of three
months or less are considered to be cash equivalents.

OIL AND GAS PROPERTIES

HEPGP follows the full cost method of accounting whereby all costs related to
the acquisition of oil and gas properties are capitalized in a single cost
center ("full cost pool") and are amortized over the productive life of the
underlying proved reserves using the units of production method. Proceeds from
property sales are generally credited to the full cost pool.

Capitalized costs of oil and gas properties may not exceed an amount equal to
the present value, discounted at 10%, of estimated future net revenues from
proved oil and gas reserves plus the cost, or estimated fair market value, if
lower, of unproved properties. Should capitalized costs exceed this ceiling,
an impairment is recognized. The present value of estimated future net
revenues is computed by applying current prices of oil and gas to estimated
future production of proved oil and gas reserves as of year end, less estimated
future expenditures to be incurred in developing and producing the proved
reserves assuming continuation of existing economic conditions.

HEPGP does not accrue costs for future site restoration, dismantlement and
abandonment costs related to proved oil and gas properties because HEPGP
estimates that such costs will be offset by the salvage value of the equipment
sold upon abandonment of such properties. HEPGP's estimates are based upon its
historical experience and upon a review of current properties and restoration
obligations.

During 1996, HEPGP adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets
to be disposed Of" ("SFAS 121"). SFAS 121 provides the standards for
accounting for the impairment of various long-lived assets. Substantially all
of HEPGP's long-lived assets consist of oil and gas properties which are
evaluated for impairment as described above. Therefore, the adoption of SFAS
121 did not have a material effect on the financial position of HEPGP.

F-35
<PAGE> 149

USE OF ESTIMATES

The preparation of the balance sheet for HEPGP in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the balance
sheet. Actual results could differ from these estimates.

GAS BALANCING

HEPGP uses the sales method for recording its gas balancing. Under this
method, HEPGP recognizes revenue on all of its sales of production, and any
over production or under production is recovered at a future date.

As of December 31, 1996, the imbalance net to HEPGP's interest is not material.
HEPGP believes that current imbalances can be made up with production from
existing wells or from wells which will be drilled as offsets to current
producing wells and the imbalance will not have a material effect on HEPGP's
results of operations, liquidity and capital resources.

ENVIRONMENTAL CONCERNS

HEPGP is continually taking actions it believes are necessary in its operations
to ensure conformity with applicable federal, state and local environmental
regulations. As of December 31, 1996, HEPGP has not been fined or cited for
any environmental violations which would have a material adverse effect upon
capital expenditures, earnings or the competitive position of HEPGP in the oil
and gas industry.

NOTE 2 - RELATED PARTY TRANSACTIONS

During the the third quarter of 1997 and the fourth quarter 1996, HEP declared
general partner distributions of $508,000 and $541,000, respectively. These
amounts have been accrued by HEPGP and are included in due from affiliates at
September 30, 1997 and December 31, 1996.

Hallwood Petroleum, Inc. ("HPI") manages and operates certain oil and gas
properties on behalf of independent joint interest owners, HEPGP and its
affiliates. In such capacity, HPI pays all costs and expenses of operations and
distributes all revenues associated with such properties. HEPGP has payables of
$264,000 and $26,000 to HPI included in due from affiliates at September 30,
1997 and December 31, 1996, respectively, which represents net operating
expenses in excess of net revenues. This balance is settled monthly.

Also included in "due from affiliates" at December 31, 1996 are amounts
advanced to Hallwood Group of $616,000 for operating purposes. This balance is
expected to be settled within approximately six months.

The note receivable from the affiliate is comprised of a $2,000,000 promissory
note due from Hallwood Group. The note bears interest at a bank's prime
interest rate plus 1% (9.25% at December 31, 1996) and has a maturity date of
May 31, 1998. HEPGP intends to extend the maturity date to May 31, 1999;
therefore, there is no current portion of long-term debt at September 30, 1997.
Principal and interest payments may be made in whole or in part from time to
time without premium or penalty prior to the maturity date.

NOTE 3 - DEBT

During December 1996, HEPGP entered into a $2,500,000 term loan agreement. The
loan bears interest at the bank's prime interest rate plus 1% (9.25% at
December 31, 1996) and monthly principal payments of $139,000 commenced
December 31, 1996. The loan matures on April 30, 1998 and is collateralized by
certain of HEPGP's direct oil and gas property interests.

As of December 31, 1996, principal payments due on HEPGP's debt were as follows
(in thousands):

F-36
<PAGE> 150

<TABLE>
<S> <C>
1997 $ 1,668

1998 693
----------

2,361
Less current maturities 1,668
----------

Long-term debt $ 693
==========
</TABLE>

F-37
<PAGE> 151

HEPGP LTD.
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
DECEMBER 31, 1996
(UNAUDITED)

The following reserve quantity and future net cash flow information for HEPGP
represents proved reserves that are located in the United States. The reserves
have been estimated by in-house engineers. A majority of these reserves has
been reviewed by independent petroleum engineers. The determination of oil and
gas reserves is based on estimates which are highly complex and interpretive.
The estimates are subject to continuing changes as additional information
becomes available.

The standardized measure of discounted future net cash flows excludes any
consideration of future income taxes for HEPGP as it is not a tax-paying
entity. Under the guidelines set forth by the Securities and Exchange
Commission (the "SEC"), the calculation is performed using year end prices. At
December 31, 1996, oil and gas prices averaged $24.13 per bbl of oil and $4.00
per mcf of gas for HEPGP. Future production costs are based on year end costs
and include severance taxes. The present value of future cash inflows is based
on a 10% discount rate. The reserve calculations using these December 31, 1996
prices result in 486,000 Bbls of oil, and 6.8 billion cubic feet of gas and a
standardized measure of $19,000,000. The standardized measure is not
necessarily representative of the market value of HEPGP's properties.

HEPGP's standardized measure of future net cash flows has been decreased by
$404,000 at December 31, 1996 for the effects of HEP's hedge contracts. This
amount represents the difference between year end oil and gas prices and the
hedge contract prices multiplied by the quantities subject to contract,
discounted at 10%.

F-38
<PAGE> 152

HEPGP LTD.
RESERVE QUANTITIES
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
GAS OIL
(Mcf) (Bbls)
----- ------
<S> <C> <C>
PROVED RESERVES:

Balance December 31, 1996 6,790 486
===== ====

PROVED DEVELOPED RESERVES:

Balance December 31, 1996 6,676 468
===== ====
</TABLE>

F-39
<PAGE> 153

HEPGP LTD.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<S> <C>
Future cash inflows $ 39,300

Future production and development costs (9,600)

Future net cash flows before discount 29,700
---------
10% discount to present value (10,700)
---------

Standardized measure of discounted future net cash flows $ 19,000
=========
</TABLE>

F-40
<PAGE> 154
================================================================================

UNTIL , 1998 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL DEALERS
EFFECTING TRANSACTIONS IN THE REGISTERED SECURITIES, WHETHER OR NOT
PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE OBLIGATIONS OF DEALERS TO DELIVER A PROSPECTUS WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.

-------------------------

-------------------------
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT MADE BY THIS PROSPECTUS AND, IF
GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES
NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE
SECURITIES OFFERED HEREBY BY ANYONE IN ANY JURISDICTION WHERE SUCH AN OFFER OR
SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OFFER OF
SOLICITATION IS NOT QUALIFIED TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY
CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE
AFFAIRS OF THE COMPANY OR THAT INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY
TIME SUBSEQUENT TO THE DATE OF THIS PROSPECTUS.
================================================================================

================================================================================

2,500,000 CLASS C UNITS

REPRESENTING LIMITED

PARTNER INTERESTS

HALLWOOD ENERGY PARTNERS, L.P.

---------------------
PROSPECTUS
---------------------

PRINCIPAL FINANCIAL

SECURITIES, INC.

LADENBURG THALMANN &
CO. INC.

WHEAT FIRST BUTCHER SINGER

FIRST UNION CAPITAL
MARKETS CORP.

================================================================================

<PAGE> 155
PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The following table sets forth the estimated expenses and costs (other than
underwriting discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered hereby:

<TABLE>
<S> <C>
Securities and Exchange Commission registration fee . . . $ 9,700
NASD filing fee . . . . . . . . . . . . . . . . . . . . . $ 3,600
American Stock Exchange listing fee . . . . . . . . . . . $ 17,500
Printing and engraving costs . . . . . . . . . . . . . . $ *130,000
Legal fees and expenses . . . . . . . . . . . . . . . . . $ *150,000
Accounting fees and expenses . . . . . . . . . . . . . . $ * 50,000
Blue Sky fees and expenses . . . . . . . . . . . . . . . $ * 5,000
Registrar and Transfer Agent's fees . . . . . . . . . . . $ * 5,000
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . $ * 4,200
-----------
Total . . . . . . . . . . . . . . . . . . . . . $ *375,000
===========
</TABLE>

*Estimated

The Partnership will pay all of such expenses to be incurred in connection
with the issuance and distribution of the securities registered hereby.

ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS; LIMITATION OF LIABILITY
FOR MONETARY DAMAGES

(a) The Partnership Agreement of HEP provides that the Partnership will
indemnify the General Partner, its affiliates and their directors, officers,
employees and agents against any and all losses, claims, damages, liabilities,
joint and several, expenses (including reasonable legal fees and expenses),
judgments, fines, settlements and other amounts arising from any and all
claims, costs, demands, actions, suits or proceedings, civil, criminal,
administrative or investigative, in which the General Partner or such other
persons may be involved or threatened to be involved, if (i) in the case of
civil actions the General Partner or such persons acted in good faith and in a
manner it reasonably believed to be in, or not opposed to, the best interests
of the Partnership and the Operating Partnerships and the General Partner's or
such other person's conduct did not constitute gross negligence or willful or
wanton misconduct and in the case of criminal actions the General Partner or
such other person had no reasonable cause to believe the conduct was unlawful
or (ii) the General Partner or such other person has been successful in
defending any such action or proceeding.

(b) The Partnership Agreement also provides that General Partner, its
affiliates and directors will not be liable for monetary damages to the
Partnership, the limited partners or assignees for errors of judgment or for
any acts or omissions of the General Partner and such other persons who acted
in good faith.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) EXHIBITS

* 1.1 - Form of Underwriting Agreement to be entered into by Hallwood
Energy Partners, L.P., Principal Financial Securities, Inc.,
Ladenburg Thalmann & Co. Inc., Wheat First Butcher Singer and
First Union Capital Markets Corp.

(1) 4.1 - Third Amended and Restated Agreement of Limited Partnership of
Hallwood Energy Partners, L. P.
(2) 4.2 - Unit Purchase Rights Agreement dated as of February 6, 1995
between HEP and The First National Bank of Boston.

II-1
<PAGE> 156
(3) 4.3 - First Amendment to the Third Amended and Restated Agreement of
Limited Partnership of Hallwood Energy Partners, L. P.
(4) 4.4 - Amendment to the Third Amended and Restated Agreement of Limited
Partnership of Hallwood Energy Partners, L.P.
5.1 - Opinion of Jenkens & Gilchrist, a Professional Corporation

8.1 - Opinion of Jenkens & Gilchrist, a Professional Corporation, with
respect to federal income tax matters

12.1 - Statement regarding computation of ratios

** 23.1 - Consent of Deloitte & Touche LLP.

* 23.2 - Consent of Williamson Petroleum Consultants, Inc.

23.3 - Consent of Jenkens & Gilchrist, a Professional Corporation
(included in Exhibits 5.1 and 8.1)

_________________
* To be filed by amendment.

** Previously filed.

(1) Incorporated by reference to Prospectus/Proxy Statement dated February
14, 1990 as supplemented March 22, 1990, March 30, 1990 and April 5,
1990, of Hallwood Energy Partners, L. P., filed as part of Registration
Statement No. 33-33452.
(2) Incorporated by reference to the same Exhibit number filed with the
Registrant's Form 8-A for Limited Partner Unit Purchase Rights filed with
the SEC on February 8, 1995.
(3) Incorporated by reference to the same exhibit number filed with the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1995.
(4) Incorporated by reference to the same exhibit number filed with the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1996.

(b) FINANCIAL STATEMENT SCHEDULES

Not applicable.

ITEM 17. UNDERTAKINGS

(a) The undersigned Registrant hereby undertakes to provide to the
Underwriter at the closing specified in the Underwriting Agreement certificates
in such denominations and registered in such names as required by the
Underwriter to permit prompt delivery to each purchaser.

(b) The undersigned registrant hereby undertakes to deliver or cause to
be delivered with the prospectus, to each person to whom the prospectus is sent
or given, the latest annual report to security holders that is incorporated by
reference in the prospectus and furnished pursuant to and meeting the
requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of
1934; and, where interim financial information required to be presented by
Article 3 of Regulation S-X are not set forth in the prospectus, to deliver, or
cause to be delivered to each person to whom the prospectus is sent or given,
the latest quarterly report that is specifically incorporated by reference in
the prospectus to provide such interim financial information.

(c) Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and controlling persons
of the Registrant pursuant to the foregoing provisions, or otherwise, the
Registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than payment by the Registrant
of expenses incurred or paid by a director, officer, or controlling person of
the Registrant in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with the
securities being registered, the Registrant will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act and will be governed
by the final adjudication of such issue.

II-2
<PAGE> 157
(d) The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part of
this Registration Statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or
(4), or 497(h) under the Securities Act shall be deemed to be part of
this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that contains a
form of prospectus shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide
offering thereof.

(e) The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.

II-3
<PAGE> 158
SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the

Registrant certifies that it has reasonable grounds to believe that it meets all
of the requirements for filing on Form S-3 and has duly caused this Amendment
No. 1 to Registration Statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Dallas, State of Texas, on the 17th
day of December, 1997.

HALLWOOD ENERGY PARTNERS, L.P.
BY: HEPGP LTD.
GENERAL PARTNER

BY: HALLWOOD G.P., INC.
GENERAL PARTNER

By: /s/ William L. Guzzetti*
-------------------------------
William L. Guzzetti
President

Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 1 to Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.

<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Anthony J. Gumbiner* Chairman of the Board and Director December 17, 1997
------------------------------------ (Principal Executive Officer)
Anthony J. Gumbiner

Director __________, 1997
------------------------------------
Brian M. Troup

/s/ William L. Guzzetti* Director December 17, 1997
------------------------------------
William L. Guzzetti

/s/ Hans-Peter Holinger* Director December 17, 1997
------------------------------------
Hans-Peter Holinger

/s/ Rex A. Sebastian* Director December 17, 1997
------------------------------------
Rex A. Sebastian

/s/ Nathan C. Collins* Director December 17, 1997
------------------------------------
Nathan C. Collins
Principal Financial and Accounting
/s/ Robert S. Pfeiffer* Officer December 17, 1997
------------------------------------
Robert S. Pfeiffer
</TABLE>

* By Cathleen M. Osborn, Attorney-in-Fact

II-4

<PAGE> 159
INDEX TO EXHIBITS

<TABLE>

Exhibit
Number Description
- ------ -----------
<S> <C>
* 1.1 - Form of Underwriting Agreement to be entered into by Hallwood Energy Partners, L.P.,
Principal Financial Securities, Inc. Ladenburg Thalmann & Co. Inc., Wheat First Butcher
Singer and First Union Capital Markets Corp.
(1) 4.1 - Third Amended and Restated Agreement of Limited Partnership of Hallwood Energy
Partners, L. P.
(2) 4.2 - Unit Purchase Rights Agreement dated as of February 6, 1995 between HEP and The First
National Bank of Boston.
(3) 4.3 - First Amendment to the Third Amended and Restated Agreement of Limited Partnership of
Hallwood Energy Partners, L. P.
(4) 4.4 - Amendment to the Third Amended and Restated Agreement of Limited Partnership of
Hallwood Energy Partners, L.P.
5.1 - Opinion of Jenkens & Gilchrist, a Professional Corporation
8.1 - Opinion of Jenkens & Gilchrist, a Professional Corporation, with respect to federal
income tax matters
12.1 - Statement regarding computation of ratios
** 23.1 - Consent of Deloitte & Touche LLP.
* 23.2 - Consent of Williamson Petroleum Consultants, Inc.
23.3 - Consent of Jenkens & Gilchrist, a Professional Corporation (included in Exhibits 5.1
and 8.1)
</TABLE>

__________
* To be filed by amendment.

** Previously filed.

<PAGE> 1
EXHIBIT 5.1

December 18, 1997

Hallwood Energy Partners, L.P.
4582 South Ulster Street Parkway, Suite 1700
Denver, Colorado 80237

Re: Hallwood Energy Partners, L.P. Offering of Class C Units

Gentlemen:

We have acted as counsel to Hallwood Energy Partners, L.P. (the
"Partnership"), a Delaware limited partnership, in connection with the offer
and sale of 2,875,000 units representing Class C limited partnership interests
in the Partnership (the "Class C Units") pursuant to a Registration Statement
on Form S-3 (the "Registration Statement"), originally filed with the
Securities and Exchange Commission under the Securities Act of 1933 on October
29, 1997.

In connection therewith, we have examined and relied upon the
original, or copies, certified to our satisfaction, of (i) The Third Amended
and Restated Agreement of Limited Partnership (the "Partnership Agreement") of
the Partnership, and the amendments thereto; (ii) minutes and records of the
corporate proceedings of the Partnership with respect to the offering of the
Class C Units and related matters; (iii) the Registration Statement and
exhibits thereto, and (iv) such other documents and instruments as we have
deemed necessary for the expression of opinions herein contained. In making
the foregoing examinations, we have assumed the genuineness of all signatures
and the authenticity of all documents submitted to us as originals, and the
conformity to original documents of all documents submitted to us as certified
or photostatic copies. As to various questions of fact material to this
opinion and as to the content and form of the Partnership Agreement, minutes,
records, resolutions and other documents or writings of the Partnership, we
have relied, to the extent we deem reasonably appropriate, upon representations
or certificates of officers or directors of the Partnership and upon documents,
records and instruments furnished to us by the Partnership, without independent
check or verification of their accuracy.

Based upon the foregoing examination, we are of the opinion that the
Class C Units to be offered as described in the Registration Statement, have
been duly authorized for issuance and upon consummation of the Offering, the
Class C Units will represent valid limited partnership interests in the
Partnership, as to which the limited partners will have no liability, subject
to the
<PAGE> 2
Hallwood Energy Partners, L.P.
December 18, 1997
Page 2

obligation of a limited partner to repay the amount of any distribution
wrongfully received from the Partnership for a period of three (3) years from
the date of the distribution.

We hereby consent to the filing of this opinion as an exhibit to the
Registration Statement and to the use of our name as it appears under the
caption "Legal Matters" in the Prospectus and Proxy Statement forming a part of
the Registration Statement. In giving such consent, we do not admit that we
come within the category of persons whose consent is required under Section 7
of the Securities Act of 1933, as amended, and the rules and regulations of the
Securities and Exchange Commission issued thereunder.

Sincerely,

JENKENS & GILCHRIST,
a Professional Corporation

By: /s/ W. ALAN KAILER
--------------------------------
W. Alan Kailer, for the Firm

<PAGE> 1

Exhibit 8.1

Opinion of Jenkens & Gilchrist, a Professional Corporation

December 17, 1997

Hallwood Energy Partners, L.P.
4582 S. Ulster Street Parkway
Suite 1700
Denver, Colorado 80237

Re: Hallwood Energy Partners, L.P. Offering of Class C Units

Dear Gentlemen:

We have acted as counsel to Hallwood Energy Partners, L.P., a Delaware
limited partnership (the "Partnership"), in connection with the offer and sale
of 2,875,000 units representing Class C limited partnership interests in the
Partnership (the "Class C Units") pursuant to a Registration Statement on Form
S-3 (the "Registration Statement") originally filed with the Securities and
Exchange Commission under the Securities Act of 1933 on October 29, 1997.
Capitalized terms not defined herein shall have the meaning ascribed to them in
the Registration Statement.

The Partnership owns a 99% limited partner interest in HEP Operating
Partners, L.P., a Delaware limited partnership ("HEPO"), and the limited
partner interest in EDP Operating, Ltd., a Colorado limited partnership
("EDPO").

You have requested our opinion with respect to certain matters in
connection with the Registration Statement.

In connection with the foregoing request, the Partnership and the
General Partner have made the following representations with respect to the
Partnership, HEPO and EDPO:

(a) The Partnership, HEPO and EDPO have been and will
continue to be operated in accordance with (i) all applicable
partnership statutes, (ii) their respective partnership agreements,
and (iii) the description thereof in the Registration Statement;

(b) That units of each of Hallwood Energy Partners, L.P.,
a Delaware limited partnership, and Energy Development Partners, a
Colorado limited partnership ("EDP") as such entities existed prior to
their merger in 1990, were traded on the American Stock Exchange on
December 17, 1987.

(c) That, from December 17, 1987 through December 31,
1997, each of Hallwood Energy Partners, L.P., a Delaware limited
partnership and EDP, as such entities existed prior to their merger in
1990, and the Partnership for all times thereafter, did not and will
not add any Substantial New Line of Business.

(d) For each taxable year beginning after December 31,
1997, less than 10% of the gross income of the Partnership will be
derived from sources other than "qualifying income" within the meaning
of Section 7704(d) of the Code; and

(e) Neither the Partnership, HEPO nor EDPO was notified
in writing on or before May 8, 1996 that its classification was under
examination; and

(f) Neither the Partnership, HEPO nor EDPO will make an
election under the Check-the-Box Regulations to treat itself as an
association taxable as a corporation.

<PAGE> 2

Based upon the foregoing representations and the facts and assumptions
described in the Registration Statement, the Code, existing regulations
thereunder, published rulings and judicial decisions currently outstanding, it
is our opinion that the discussion of federal income tax law set forth in the
Registration Statement under the headings "Summary of Material Tax
Considerations," "Tax Risks" and "Material Federal Income Tax Considerations"
is correct.

The information set forth herein is as of the date hereof. We assume
no obligation to advise you of changes that may thereafter be brought to our
attention. Our opinion is based upon laws, regulations, published rulings and
judicial decisions in effect at the date hereof, and we do not opine with
respect to any law, regulation, rule, or governmental policy that may be
enacted or adopted after the date hereof, nor assume any responsibility to
advise you of such future changes that may affect our opinions. An opinion
represents only counsel's best legal judgement as to the particular issues and
is not binding on the IRS or the courts. No ruling from the IRS has been
requested or received with respect to the issues discussed herein and no
assurance can be provided that the opinion and statements set forth herein
would be sustained by a court if challenged by the IRS.

We are rendering this opinion as of the time the Registration
Statement becomes effective. We hereby consent to the use of our name in the
Registration Statement and to the filing of this opinion as an exhibit to the
Registration Statement. This consent does not constitute an admission that we
are "experts" within the meaning of such term as used in the Securities Act of
1933.

Respectfully submitted,

JENKENS & GILCHRIST, P.C.

By: /s/ WILLIAM P. BOWERS
------------------------------------------
William P. Bowers,
Authorized Signatory

<PAGE> 1

Exhibit 12.1

COMPUTATION OF RATIOS

The following table sets forth the computations used in determining
the ratio of earnings to fixed charges and preferred distributions.

<TABLE>
<CAPTION>
NINE MONTHS NINE MONTHS YEAR YEAR
ENDED ENDED ENDED ENDED
9/30/97 9/30/96 12/31/96 12/31/95
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges

(d)
Net income $ 9,924 $ 11,533 $ 15,726 $ (9,031)

less; equity in earnings of HCRC $ (1,384) $ (1,227) $ (1,768)

Add back interest (a) $ 2,137 $ 2,884 $ 3,659 $
-------- -------- -------- --------

Adjusted earnings (b) $ 10,677 $ 13,190 % 17,617

Interest $ 2,137 $ 2,884 $ 3,659 $

Class C Distributions $ 4,98 $ 498 $ 662 $
-------- -------- -------- --------

Total interest plus preferred
dividends (c) $ 2,635 $ 3,382 $ 4,321

Ratio of Earnings to fixed charges
and preferred distributions (b)/(c) 4.05 3.90 4.08
======== ======== ========

<CAPTION>
YEAR YEAR YEAR
ENDED ENDED ENDED
12/31/94 12/31/93 12/31/92
-------- -------- --------
<S> <C> <C> <C>
Ratio of Earnings to Fixed Charges (d)

Net income $(10,093) $ 13,064 $ 3,613

less; equity in earnings of HCRC $ (112) $ (732)

Add back interest (a) $ $ 4,203 $ 5,893
-------- -------- --------

Adjusted earnings (b) $ 17,155 $ 8,774

Interest $ $ 4,203 $ 5,893

Class C Distributions $ $ 0 $ 0
-------- -------- --------

Total interest plus preferred
dividends (c) $ 4,203 $ 5,893

Ratio of Earnings to fixed charges
and preferred distributions (b)/(c) 4.08 1.49
======== ======== ========
</TABLE>

(a) Equals total interest, less non cash interest expense
(d) Earnings were negative, therefore calculation cannot be made.