UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    Form 10-K

MARK ONE
[X]     ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE
        ACT OF 1934

                   For the Fiscal Year Ended December 31, 1998

[ ]     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 
        EXCHANGE ACT OF 1934

                          Commission File Number 1-8921



                         HALLWOOD ENERGY PARTNERS, L. P.
             (Exact name of registrant as specified in its charter)



              Delaware                                                84-0987088
(State or other jurisdiction of                                 (I.R.S. Employer
incorporation or organization)                            Identification Number)

 4582 South Ulster Street Parkway
                  Suite 1700
             Denver, Colorado                                              80237
(Address of principal executive offices)                              (Zip Code)

       Registrant's telephone number, including area code: (303) 850-7373

           Securities Registered Pursuant to Section 12(b) of the Act:

                                                           Name of each exchange
        Title of each class                                  on which registered
Class A Units of Limited Partnership Interests           American Stock Exchange
Class C Units of Limited Partnership Interests           American Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding 12 months (or for such  shorter  period that the  registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days. Yes [x] No [ ]

Indicate by check mark if disclosure of delinquent  filers  pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of  registrant's  knowledge,  in  definitive  proxy  or  information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

The  aggregate  market  value  of  the  Class  A  and  Class  C  Units  held  by
nonaffiliates  of  the  registrant  as  of  March  24,  1999  was  approximately
$30,238,000.
Number of Units outstanding as of March 24, 1999

Class A                                                      10,011,852
Class B                                                         143,773
Class C                                                       2,464,063





<PAGE>


                                     PART I


ITEM 1 - BUSINESS

Hallwood Energy Partners, L.P. ("HEP" or the "Partnership") 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.
HEP's future growth will be driven by a combination  of  development of existing
projects,  exploration  for new  reserves  and select  acquisitions.  HEPGP Ltd.
("HEPGP")  became the  general  partner of HEP on  November  26,  1996 after the
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 by 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.

HEP  does  not  engage  in any  other  line of  business  nor  does it have  any
employees.  Hallwood Petroleum, Inc. ("HPI"), an affiliated entity, operates the
properties and  administers the day to day activities of HEP and its affiliates.
On March 24, 1999, HPI has 108 employees.

Marketing

The oil and gas produced from the  properties  owned by HEP 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 in the  areas  where  the  majority  of  producing  properties  are
located. In response to the volatility in the oil markets,  HEP has entered into
financial  contracts for hedging the price of 2% of its estimated oil production
for 1999.

All of HEP's natural gas  production is sold on the spot market or in short-term
contracts and is transported in intrastate  and  interstate  pipelines.  HEP has
entered into financial contracts for hedging the price of between 30% and 45% of
its estimated gas production for 1999 through 2002.

The purpose of the hedges is to provide  protection  against price decreases and
to provide a measure of stability in the volatile environment of oil and natural
gas  spot  pricing.  The  amounts  received  or paid  upon  settlement  of these
contracts are recognized as an increase or decrease in oil or gas revenue at the
time the hedged volumes are sold.

Both oil and natural  gas are  purchased  by  refineries,  major oil  companies,
public  utilities,  industrial  customers  and  other  users and  processors  of
petroleum  products.  HEP 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 HEP's  business
because there are numerous other  purchasers in the areas in which HEP sells its
production.  However,  for the years ended  December  31,  1998,  1997 and 1996,
purchases  by the  following  companies  exceeded  10% of the  total oil and gas
revenues of the Partnership:


<PAGE>



                                         1998              1997             1996
                                         ----              ----             ----

Conoco Inc.                                23%             20%               28%
El Paso Field Services Company             11%             11%
Marathon Petroleum Company                                 16%               11%

Factors,  if they  were to occur,  which  might  adversely  affect  HEP  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.

Competition

HEP 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.  As described above under "Marketing,"  production
is sold on the spot market, thereby reducing sales competition; however, oil and
gas must compete with coal, atomic energy,  hydro-electric power and other forms
of energy.

Regulation

Production and sale of oil and gas is subject to federal and state  governmental
regulation  in a variety of ways,  including  environmental  regulations,  labor
laws,  interstate  sales,  excise  taxes and  federal and Indian  lands  royalty
payments.  Failure  to  comply  with  these  regulations  may  result  in fines,
cancellation of licenses to do business and  cancellation  of federal,  state or
Indian leases.

The  production of oil and gas is subject to regulation by the state  regulatory
agencies  in the  states in which HEP does  business.  These  agencies  make and
enforce regulations to prevent waste of oil and gas and to protect the rights of
owners to produce oil and gas from a common reservoir.  The regulatory  agencies
regulate the amount of oil and gas produced by  assigning  allowable  production
rates to wells capable of producing oil and gas.

Environmental Considerations

The  exploration  for, and  development of, oil and gas involves 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. 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.  As of December 31, 1998,  HEP has not been fined or
cited for any  environmental  violations  which  would have a  material  adverse
effect  upon  capital  expenditures,  earnings,  cash  flows or the  competitive
position of HEP in the oil and gas industry.

Insurance Coverage

HEP is subject to all the risks inherent in the exploration for, and development
of, oil and gas, including blowouts,  fires and other casualties.  HEP maintains
insurance  coverage as is  customary  for  entities of a similar size engaged in
operations  similar to that of HEP, but losses can occur from uninsurable  risks
or in amounts in excess of existing  insurance  coverage.  The  occurrence of an
event which is not  insured or not fully  insured  could have an adverse  impact
upon HEP's earnings, cash flows and financial position.




<PAGE>


Issues Related to the Year 2000

General.  The following  Year 2000  statements  constitute a Year 2000 Readiness
Disclosure  within  the  meaning  of the Year  2000  Information  and  Readiness
Disclosure  Act of 1998.  The Year 2000 problem has arisen because many existing
computer  programs  use only the last two digits to refer to a year.  Therefore,
these  computer  programs do not properly  recognize and process  date-sensitive
information  beyond  1999.  In  general,  there  are two areas  where  Year 2000
problems  may  exist  for  the  Partnership:   information  technology  such  as
computers,  programs and related systems ("IT") and  non-information  technology
systems such as embedded technology on a silicon chip ("Non IT").

The Plan.  The  Partnership's  Year 2000 Plan (the "Plan") has four phases:  (i)
assessment,  (ii) inventory,  (iii) remediation,  testing and implementation and
(iv) contingency plans.  Approximately  twelve months ago, the Partnership began
its phase one assessment of its particular exposure to problems that might arise
as a result of the new millennium. The assessment and inventory phases have been
substantially  completed and have identified the  Partnership's  IT systems that
must be updated or replaced in order to be Year 2000  compliant.  In particular,
the software used by the Partnership for reservoir  engineering  must be updated
or  replaced.  Remediation,  testing  and  implementation  are  scheduled  to be
completed  by June 30,  1999,  and the  contingency  plans  phase of the Plan is
scheduled to be completed by September 30, 1999.

However,  the  effects of the Year 2000  problem on IT systems  are  exacerbated
because of the  interdependence  of computer  systems in the United States.  The
Partnership's  assessment  of the  readiness of third  parties  whose IT systems
might have an impact on the  Partnership's  business has thus far not  indicated
any material problems;  responses have been received to approximately 50% of the
172 inquiries made.

With regard to the Partnership's Non IT systems,  the Partnership  believes that
most  of  these  systems  can  be  brought  into  compliance  on  schedule.  The
Partnership's assessment of third party readiness is not yet completed.  Because
Non IT systems are embedded  chips,  it is difficult to determine  with complete
accuracy  where  all  such  systems  are  located.  As  part  of its  Plan,  the
Partnership  is making formal and informal  inquiries of its vendors,  customers
and  transporters  in an effort to determine  the third party systems that might
have embedded technology requiring remediation.

Estimated  Costs.  Although  it is  difficult  to  estimate  the total  costs of
implementing  the Plan  through  January 1, 2000 and beyond,  the  Partnership's
preliminary  estimate  is that such costs  will not be  material.  To date,  the
Partnership  has determined  that its IT systems are either  compliant or can be
made compliant for less than $150,000.  However,  although  management  believes
that its estimates are  reasonable,  there can be no assurance,  for the reasons
stated in the next paragraph, that the actual cost of implementing the Plan will
not differ materially from the estimated costs.

Potential  Risks.  The  failure to correct a material  Year 2000  problem  could
result  in  an  interruption  in,  or a  failure  of,  certain  normal  business
activities or operations.  This risk exists both as to the  Partnership's IT and
Non IT systems, as well as to the systems of third parties.  Such failures could
materially and adversely affect the  Partnership's  results of operations,  cash
flow and financial  condition.  Due to the general  uncertainty  inherent in the
Year  2000  problem,  resulting  in part from the  uncertainty  of the Year 2000
readiness of third party suppliers, vendors and transporters, the Partnership is
unable to determine at this time whether the  consequences of Year 2000 failures
will have a material  impact on the  Partnership's  results of operations,  cash
flow or financial  condition.  Although the Partnership is not currently able to
determine the consequences of Year 2000 failures, its current assessment is that
its area of  greatest  potential  risk in its third  party  relationships  is in
connection  with the  transporting  and marketing of the oil and gas produced by
the  Partnership.  The  Partnership  is contacting  the various  purchasers  and
pipelines  with which it regularly  does  business to  determine  their state of
readiness for the Year 2000.  Although in general the  purchasers  and pipelines
will not guaranty their state of readiness,  the responses received to date have
indicated no material  problems.  The Partnership  believes that in a worst case
scenario,  the failure of its purchasers and transporters to conduct business in
a normal fashion could have a material  adverse effect on cash flow for a period
of six to  nine  months.  The  Partnership's  Year  2000  Plan  is  expected  to
significantly reduce the Partnership's level of uncertainty about the compliance
and readiness of these  material  third  parties.  The evaluation of third party
readiness  will be  followed by the  Partnership's  development  of  contingency
plans.

Cautionary  Statement  Regarding  Forward-Looking   Statements.  The  dates  for
completion  of the  phases of the Year 2000 Plan are based on the  Partnership's
best estimates,  which were derived using numerous assumptions of future events.
Due to the general uncertainty  inherent in the Year 2000 problem,  resulting in
part from the  uncertainty of the Year 2000 readiness of  third-parties  and the
interconnection  of computer systems,  the Partnership cannot ensure its ability
to timely and  cost-effectively  resolve problems  associated with the Year 2000
issue that may affect its  operations  and business.  Accordingly,  partners are
cautioned  that certain  events or  circumstances  could cause actual results to
differ materially from those projected, estimated or predicted.


ITEM 2 - PROPERTIES

Exploration and Development Projects and Acquisitions

In 1998, HEP incurred  $40,936,000 in direct  property  additions,  development,
exploitation and exploration  costs. The costs were comprised of $28,756,000 for
property acquisitions and approximately $12,180,000 for domestic exploration and
development.  The  expenditures  resulted  in  the  drilling,  recompletion,  or
workover of 44  development  wells and 36  exploration  wells.  HEP completed 39
development wells (89%) and 18 exploration wells (50%) for an overall completion
rate of 71%.  HEP's  1998  capital  program  led to the  replacement,  including
revisions  to prior year  reserves,  of 72% of 1998  production  using  year-end
prices of $10.00 per bbl and $1.90 per mcf.  Using  five-year  average prices of
$16.75 per bbl and $1.86 per mcf, HEP's reserve  replacement for 1998 would have
been  136%  of 1998  production.  Management  utilizes  average  price  reserves
internally because it believes these prices more accurately reflect the value to
be achieved over time. Excluded from these calculations are sales of reserves in
place in 1998,  which were  approximately  2% of 1998  production.  In 1998, HEP
expended  approximately  $1,495,000  for  land  and  seismic  costs,  which  HEP
anticipates will yield prospects for 1999 and subsequent years.

Property Sales

During 1998, HEP received approximately $454,000 for the sale of 67 nonstrategic
properties located in eight states.

Regional Area Descriptions and 1998 Capital Budget

The  following  discussion of HEP's  properties  and capital  projects  contains
forward-looking statements that are based on current expectations, estimates and
projections about the oil and gas industry, management's beliefs and assumptions
made  by   management.   Words  such  as  "projects,"   "believes,"   "expects,"
"anticipates,"  "estimates,"  "plans,"  "could,"  variations  of such  words and
similar  expressions are intended to identify such  forward-looking  statements.
Please  refer  to  the  section   entitled   "Cautionary   Statement   Regarding
Forward-Looking  Statements"  for a discussion of factors which could affect the
outcome of the forward-looking statements.

Greater Permian Region

HEP has significant interests in the Greater Permian Region, which includes West
Texas and  Southeast  New  Mexico.  In this  region,  HEP has  interests  in 537
productive  oil and gas wells (423 of which are operated),  38 operated  shut-in
oil and gas wells and 17 (15 operated)  salt water  disposal  wells or injection
wells.  In 1998,  HEP expended  approximately  $12,070,000  (29%) of its capital
budget  on  projects  in this  area.  HEP  spent  approximately  $2,598,000  for
drilling,  recompletion, or workover of 24 development wells and for drilling 18
exploration wells.  Seventy-nine percent of the wells drilled or recompleted are
producing.  The following is a  description  of the  significant  areas and 1998
capital projects within the Greater Permian Region.


<PAGE>


Arcadia  Acquisition.  In October 1998, HEP purchased for $8,200,000 oil and gas
properties  including  interests in approximately 570 wells located primarily in
Texas, numerous proven and unproven drilling locations, exploration acreage, and
3-D seismic data. HPI operates  approximately  85% of the proven property value.
The acquisition added estimated proven reserves of approximately 565,000 barrels
of oil and 5.3 billion  cubic feet of natural gas at five-year  average  prices,
and  approximately  465,000 barrels of oil and 5.3 billion cubic feet of natural
gas at year-end  pricing.  HEP's estimated  proven reserve  addition of 8.7 bcfe
represents  approximately  47% of HEP's 1998  production  at  five-year  average
prices,  and 43% of HEP's 1998 production at year-end prices. HEP estimates that
gross 1999 production from the properties  could be  approximately  1.1 bcfe. In
1999, HEP plans to divest  approximately 400 of the wells acquired from Arcadia.
The wells to be sold are nonstrategic, nonoperated, and represent only 6% of the
acquisition's  production  and 4% of its average  price  value.  During 1999 HEP
plans to study the areas for future development project implementation.

Carlsbad/Catclaw  Area.  HEP's  interests  in the  Carlsbad/Catclaw  Area  as of
December 31, 1998 consisted of 93 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 37 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.  In 1998,  HEP  spent
approximately $886,000 recompleting or drilling nine producing development wells
and drilling one unsuccessful exploration well. HEP expects to continue operated
development drilling in the Hat Mesa Field.

East Keystone Area.  HEP's interest in the East Keystone Area as of December 31,
1998  consisted  of 55  producing  wells,  37 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.  During 1998, HEP had
eight  development  projects,  of which  seven  were  successful.  HEP's  future
development plans include a total of three projects for this area.

Merkle Area. HEP's interest in the Merkle Area as of December 31, 1998 consisted
of 29  producing  wells,  16 of which are  operated  by HPI in Taylor  and Nolan
Counties,  Texas.  HEP'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.  Based  on its  initial  success  in the
nonoperated  Merkle Area, HEP acquired 74 additional  miles of  proprietary  3-D
seismic  data  adjacent  to the  nonoperated  area.  HEP's focus in this area is
exploration of the Canyon, Strawn, Flippen, Tannehill and Ellenberger formations
at depths of 2,500 to 6,500 feet. In 1998, HEP drilled 11 exploration  wells and
one development well, nine of which were completed.  HEP incurred  approximately
$975,000 in costs in 1998 for the 12 wells  drilled.  HEP owns an average  28.5%
working interest in the wells. Even with current low crude oil prices, continued
drilling in this area is economic,  and HEP anticipates additional 1999 drilling
to continue to exploit the reef structures.

Griffin Project.  In 1998, HEP purchased land for $102,000 and incurred costs of
approximately $420,000 to drill three exploration wells and one development well
in Gaines County, Texas. None of the four nonoperated 7,500 foot Leonardian Sand
wells was  successful.  Due to limited  delineation  drilling  potential in this
crude oil focused area and low oil prices,  HEP will delay  future  drilling and
evaluate  the  viability  of the  remaining  exploration  projects.  HEP owns an
average 22% working interest in the prospect area.

Spraberry  Area.  HEP's interests in the Spraberry Area consist of 360 producing
wells,  13 salt  water  disposal  wells and 36 shut-in  wells in Dawson,  Upton,
Reagan and Irion Counties,  Texas. HPI operates 380 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.  During 1998, HEP drilled or recompleted three wells, all of
which  are  producing.  As a result  of low  crude  oil  prices,  HEP  abandoned
twenty-three  wells in this area in 1998.  During 1999,  HEP plans to shut-in 29
uneconomic  wells and has scheduled 25  additional  wells for  abandonment.  The
wells  scheduled for shut-in  produce,  in total,  only 150 mcfe per day, net to
HEP, and were operating at a net loss to HEP of $270,000 per year.  Future plans
for this area include  eight  development  wells and  workovers  and  additional
projects contingent upon future evaluation. The price of crude oil must increase
before these projects can be considered viable.


<PAGE>


Gulf Coast Region

HEP has  significant  interests in the Gulf Coast Region in Louisiana  and South
and East  Texas.  HEP's  most  significant  interest  in the Gulf  Coast  Region
consists of 23 producing gas wells 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 11 are  operated  by HPI.  The two most
significant wells in the area are the A.L.  Boudreaux #1 and the G.S.  Boudreaux
Estate #1. In South and East Texas,  HEP has interests in 203 wells, 65 of which
are operated by HPI and produce primarily from the Austin Chalk,  Paluxy,  Lower
Frio and Cotton Valley  formations  at depths from 7,000 to 13,000 feet.  During
1998, HEP expended approximately  $5,821,000 (14%) of its capital budget in this
region.
The  following  discussion  relates to major 1998  capital  projects  within the
region.

Bell Project.  HEP has a 30% working interest in an operated project to evaluate
the Buda, Carrizo,  Woodbine,  and Dexter sands in Houston County,  Texas. HEP's
drilling  costs in 1998 for a  9,200-foot  horizontal  well  were  approximately
$615,000.  The well  encountered  Buda  pay and  sales  of  production  began in
December 1998, after gas processing equipment was installed.  The well primarily
produces oil. HEP achieved  gross  sustained  production  rates of 8.2 mmcfe per
day; however, due to current low oil prices,  flowing rates have been reduced to
approximately  4 mmcfe per day. HEP also incurred  $375,000 in 1998 for land and
leasehold  costs  relating  to the  project.  HEP plans  additional  delineation
drilling  in 1999.  HEP  anticipates  that  single or  multi-lateral  horizontal
drilling will be the principal  drilling  practice used in this area.  The gross
targeted  potential for the project could be 2.4 bcfe per well.  There can be no
assurance, however, that any wells drilled will be successful.

Bison Prospect.  HEP participated in a nonoperated  18,000 foot exploratory well
in  Lafayette  Parish,  Louisiana,  targeting  a large  Klump  sands  structure.
Drilling  problems  prevented the well from reaching total depth and testing the
primary target horizon in the prospect;  however,  the secondary  target horizon
was tested and found to be  non-productive.  The well was plugged and abandoned.
Total land and drilling  costs  incurred by HEP during 1998 for its 7.5% working
interest were approximately $550,000.

Blue Moon Project.  During 1998,  HEP entered into a farmout  arrangement  under
which  it  contributed  acreage  to  a  project  drilled  in  Lafayette  Parish,
Louisiana.  A well was  recently  completed  and tested over 14 mmcfe of gas per
day.  HEP's after payout  working  interest in the well depends on unit boundary
determinations, but HEP anticipates that its working interest will be between 5%
and 7%. HEP paid no capital  costs for its  interest in the well,  and payout is
expected to occur during the second quarter of 1999.

East Smith Point. In 1998, HEP  participated in a Frio sand  recompletion  and a
3-D seismic review of the deep Vicksburg located in Chambers County,  Texas. HEP
owns a 49% working interest in the project and spent approximately  $305,000 for
drilling costs and approximately  $426,000 for land and geologic and geophysical
data. In 1998, the first 14,000-foot recompletion was unsuccessful.
HEP does not plan additional activity in this area.

Esperanza Project. HEP owns a 7.9% working interest in a nonoperated 15,400-foot
directional  exploration  discovery in the Wilcox  formation  in LaVaca  County,
Texas.  The natural gas prospect was  developed  using  proprietary  3-D seismic
data, and the prospect could have a gross target of 60 bcf. The initial well has
been completed and showed gross production rates of 10 mmcfd at a flowing tubing
pressure of 9,000 psi. HEP spent approximately $365,000 in 1998 for its share of
costs.  HEP plans to participate in additional  wells in 1999 to further exploit
this discovery.

Intercoastal  Prospect.  In 1998,  HPI took over operation of a well in which it
did not own an interest in Vermilion Parish, Louisiana. The Planulina sands were
faulted out in the original wellbore, and HEP sidetracked the well at a depth of
14,467  feet to test the  sands.  The  well  was  drilled  and  logged,  and the
objective sands, although well-developed,  were found to contain water. The well
was plugged and abandoned. HEP spent $263,000 to test the concept.


<PAGE>


Mirasoles  Project.  In 1998,  HEP spent  approximately  $430,000 for land costs
related to the Mirasoles  project in Kenedy County,  Texas. HEP owns an interest
in 63  square  miles of  proprietary  3-D  seismic  data  which  defines a large
structural  prospect  that could have a gross  potential of 395 bcfe.  HEP spent
approximately  $941,000 in 1998 for its 17.5% working interest share of the cost
of drilling a 17,000-foot Frio formation  exploration well. The exploratory well
is being completed, and depending upon test results,  additional delineation and
development drilling could be required to properly exploit the structure.  There
can be no assurance, however, that any well drilled will be successful.

Whitewater  Field.  HEP's  share of 1998  costs  associated  with  plugging  two
nonoperated near shore platform wells in Nueces County,  Texas was approximately
$600,000. HEP has abandoned this field and plans no further activity.

Rocky Mountain Region 

HEP has  significant  interests  in the Rocky  Mountain  Region,  which  include
producing  properties  in  Colorado,  Montana,  North Dakota and  Northwest  New
Mexico.  HEP has interests in 207 producing oil and gas wells,  168 of which are
operated by HPI, 27 shut-in  wells,  25 of which are  operated by HPI,  and five
salt water disposal wells. HEP expended  approximately  $21,810,000 (53%) of its
1998  capital  budget in this area.  Approximately  $17,291,000  of the  capital
budget was used for the purchase of the volumetric  production payment discussed
below.  In 1998,  HEP spent  approximately  $3,125,000  to  expand a New  Mexico
gathering system, to recomplete or drill 12 development wells and to drill three
exploration wells. Twelve of the wells were completed. A discussion of the major
projects in the region follows.

Cajon  Lake  Field.  In 1998,  HEP  sidetracked  a  6,000-foot  Ismay  formation
exploration  well in San Juan County,  Utah.  HEP  developed  the prospect  from
proprietary 3-D seismic data and HPI is the operator of the project. HEP owns an
approximate 15% working interest in the project and spent approximately $120,000
to complete the exploration well in 1998. Sales of crude oil production began in
November;  however,  production will be significantly  curtailed until a natural
gas pipeline is  constructed to eliminate  flaring.  HEP projects that the fully
developed prospect could have 6 bcfe gross potential. There can be no assurance,
however,  that any additional wells drilled will be successful.  Despite low oil
prices, additional delineation drilling is anticipated in 1999.

Colorado Western Slope Project.  HEP drilled and completed two 5,500-foot Dakota
Formation wells in the Piceance Basin in western  Colorado.  HEP owns an average
29% working interest in the wells.  The wells had a combined initial  production
rate of 1.5 mmcf per day, and both wells began sales of  production in the third
quarter of 1998. In 1998, HEP also  recompleted an additional  well. Total costs
in 1998 for the three  wells were  approximately  $390,000.  HEP has  identified
fourteen additional development  locations.  HEP projects that the total project
area could have  gross  potential  reserves  of 0.8 bcfe,  which is the  typical
reserve  potential for this area. There can be no assurance,  however,  that any
additional wells drilled will be successful.

Toole  County  Area.  HEP's  interests  in the Toole  County Area  consist of 61
producing  wells and 17 shut-in wells,  66 of which are operated by HPI. The oil
wells produce from the Nisku  formation at depths of  approximately  3,000 feet,
and the gas wells  produce  from the Bow  Island  formation  at depths of 900 to
1,200 feet. In 1998, HEP drilled three  horizontal wells in the East Kevin Field
to the Nisku  formation.  Two of the oil wells were  completed  and had combined
initial production rates of 1.3 mmcfe per day. HEP has a 50% working interest in
the project and spent approximately $728,000 in 1998. Because of current low oil
prices in this sour,  lower gravity  crude area,  HEP has halted the drilling of
additional development wells and has postponed the re-entry and sidetrack of the
remaining well drilled in 1998.



<PAGE>


San Juan Basin Project - Colorado.  In July 1996, HEP and its affiliate Hallwood
Consolidate  Resources  Corporation  ("HCRC") acquired  interests in 34 wells in
LaPlata  County,  Colorado  producing  from  the  Fruitland  Coal  formation  at
approximately 3,000 feet. An unaffiliated large East Coast financial institution
formed an entity to utilize tax credits generated from the wells. All production
from the wells generates an additional payment of approximately $.68 per mcf. An
affiliate of Enron Corp.  financed the project  through a volumetric  production
payment ("VPP").  During May 1998, a limited  liability company owned equally by
HEP and HCRC, purchased the VPP from the affiliate of Enron Corp. HEP funded its
$17,291,000  share  of the  acquisition  price  from  operating  cash  flow  and
borrowings  under  its  Credit  Agreement.  As a result of its  acquisition  HEP
replaced the higher cost and  administratively  burdensome  VPP  financing  with
lower cost conventional  borrowings under its Credit  Agreement.  At the time of
the purchase, HEP entered into a financial contract to hedge the volumes subject
to the  production  payment  at an average  price of $2.11 per mmbtu.  Under the
terms of the original 1996  transaction,  HEP and HCRC were already  responsible
for costs  associated  with the wells.  HPI has managed and  operated  the wells
since July 1996, and has increased the wells' gross  production  from 14 mmcf to
approximately  23.5 mmcf per day through workovers and gas gathering  facilities
improvement  programs.  The  acquisition  increased  HEP's current average daily
production by 6.25 mmcf per day.

San Juan  Basin  Project - New  Mexico.  HEP's  interest  in the San Juan  Basin
consists  of 51  producing  gas wells and 10 shut-in  wells  located in San Juan
County,  New Mexico.  HPI operates all 51 producing  wells in New Mexico,  31 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.  Costs associated with expansion of the gathering system
for HEP's coalbed methane  properties  totaled  approximately  $1,028,000 during
1998.  The  expansion  of  the  gathering  system  significantly  increased  gas
gathering,  processing and compression  capacity for the associated  properties,
which  resulted in gross  production  increases of 3.0 mmcf per day in 1998.  In
addition to proceeds  from the sale of gas. HEP also  receives a payment of $.36
per mcf for tax credits  generated  by  production  from the 31 coalbed  methane
wells.

Other

HEP owns various other interests in properties in Kansas,  Oklahoma,  California
and  South  Central  Texas.  The  remaining  $1,235,000  of HEP's  1998  capital
expenditures  were  incurred in this area.  The costs  include  $325,000  for an
unsuccessful  exploration project in Carter County,  Oklahoma,  $157,000 for the
completion of an exploration well in Canadian County,  Oklahoma and for drilling
four  unsuccessful  exploration  wells  in Yolo  County,  California  and  other
miscellaneous  projects.  During 1998, HEP also  participated in two nonoperated
3-D seismic projects in nearby Solano and Colusa Counties, California. HEP is in
the process of divesting its interests in California projects.

Peru  Block Z-3  Project.  HEP's  partner  on the  Peruvian  offshore  Z-3 Block
completed  1,200 miles of 2-D seismic data  acquisition  to supplement  existing
seismic data. Data interpretation is in progress, and it will be reviewed by HEP
in the first  quarter of 1999.  HEP has a 7.5% working  interest in the project,
but it will not incur  capital  costs until actual  drilling  operations  begin.
Although the production-sharing  contract provides that drilling operations must
begin no later than January 2002, it is anticipated that the Peruvian government
will enact legislation to extend the period for all drilling  commitments by one
year.

For 1999,  HEP's capital  budget,  which will be paid from cash  generated  from
operations  and  cash on hand  has been  set at  $11,848,000.  HEP has  budgeted
continued  low oil prices for 1999 which  significantly  impacts cash  generated
from operations. Consequently, the capital budget has been set at a lower amount
than the budget for past years.  The capital  budget for 1999 will be reduced if
oil and gas prices decrease further.


<PAGE>


Partnership Reserves, Production and Discussion by Significant Regions

The following  table  presents the December 31, 1998 reserve data by significant
regions.
<TABLE>
<CAPTION>

                                    Proved Reserve Quantities            Present Value of Future Net Cash Flows
                                                                        Proved            Proved
                                   Mcf of Gas       Bbls of Oil      Undeveloped        Developed           Total
                                                                    (In thousands)

<S>                                   <C>               <C>           <C>               <C>              <C>     
Greater Permian Region                18,471            2,774                            $ 16,542         $ 16,542
Gulf Coast Region                     23,555              988           $ 1,791            36,146           37,937
Rocky Mountain Region                 50,956              612                              42,768           42,768
Other                                  1,957              113                19             3,734            3,753
                                    --------          -------          --------          --------       ----------
                                      94,939            4,487           $ 1,810          $ 99,190         $101,000
                                     =======           ======            ======           =======          =======
</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, 1998                  Year Ended December 31, 1997
                                     Natural Gas            Bbls of Oil            Natural Gas            Bbls of Oil
                                        (mcf)                 (bbls)                  (mcf)                 (bbls)
                                 (In thousands)

<S>                                      <C>                      <C>                   <C>                     <C>
Greater Permian Region                   2,893                    401                   2,803                   423
Gulf Coast Region                        5,291                    175                   4,859                   184
Rocky Mountain Region                    5,233                    133                   3,562                   100
Other                                      620                     78                     550                    63
                                      --------                  -----                --------                 -----
                                        14,037                    787                  11,774                   770
                                        ======                   ====                  ======                  ====
</TABLE>

The following  table presents the  Partnership's  extensions and  discoveries by
significant regions.
<TABLE>
<CAPTION>

                                    For the Year Ended December 31, 1998          For the Year Ended December 31, 1997
                                     Mcf of Gas             Bbls of Oil            Mcf of Gas             Bbls of Oil
                                 (In thousands)

<S>                                      <C>                    <C>                   <C>                     <C>
Greater Permian Region                     217                    167                   1,423                   232
Gulf Coast Region                        1,201                    164                   1,527                    75
Rocky Mountain Region                       78                     83                   1,153                   490
Other                                       46                      1                     125                    20
                                       -------                 ------                  ------                 -----
                                         1,542                    415                   4,228                   817
                                         =====                   ====                   =====                  ====
</TABLE>



<PAGE>


Average Sales Prices and Production Costs

The  following  table  presents  the average oil and gas sales price and average
production  costs per  equivalent mcf of gas computed at the ratio of six mcf of
gas to one barrel of oil.
<TABLE>
<CAPTION>

                                                       1998              1997              1996
                                                      ------            ------            -----

<S>                                                    <C>               <C>               <C>   
Oil and condensate -
  includes the effects of hedging (per bbl)            $13.65            $19.08            $20.10
Natural gas -
   includes the effects of hedging (per mcf)             2.02              2.31              2.24
Production costs (per equivalent mcf of gas)              .65               .67               .62
</TABLE>

Productive Oil and Gas Wells

The following  table  summarizes the productive oil and gas wells as of December
31, 1998 attributable to HEP's direct interests.  Productive wells are producing
wells and wells capable of production. Gross wells are the total number of wells
in  which  HEP has an  interest.  Net  wells  are the  sum of  HEP's  fractional
interests owned in the gross wells.

                                              Gross              Net

Productive Wells
  Oil                                          1,263               164
  Gas                                            352                69
                                               -----              ----
    Total                                      1,615               233
                                               =====               ===

Oil and Gas Acreage

The following table sets forth the developed and undeveloped  leasehold  acreage
held  directly by HEP as of December 31, 1998.  Developed  acres are acres which
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 and gas, regardless of whether or not
such acreage contains proved reserves. Gross acres are the total number of acres
in which HEP has a working  interest.  Net acres are the sum of HEP's fractional
interests owned in the gross acres.

                                            Gross        Net

Developed acreage                           101,257      46,771
Undeveloped acreage                         323,108      82,976
                                            -------    --------
    Total                                   424,365     129,747
                                            =======     =======

HEP holds undeveloped acreage in Texas, Louisiana, Montana, Wyoming, New Mexico,
Kansas, Colorado and North Dakota.


<PAGE>


Drilling Activity

The following table sets forth the number of wells  attributable to HEP's direct
interests drilled in the most recent three years.
<TABLE>
<CAPTION>

                                                               Year Ended December 31,
                                               1998                        1997                        1996
                                              ------                      ------                      -----
                                       Gross          Net          Gross          Net          Gross          Net 

Development Wells:
<S>                                      <C>          <C>            <C>          <C>            <C>          <C>
   Productive                            12           3.6            23           4.5            29           6.6
   Dry                                    5           1.5             5            .8             4            .9
                                        ---           ---           ---          ----           ---          ----
    Total                                17           5.1            28           5.3            33           7.5
                                         ==           ===            ==           ===            ==           ===

Exploratory Wells:
   Productive                            17           4.3            14           2.2             2            .2
   Dry                                   17           3.0            22           5.4             4            .6
                                         --           ---            --           ---             -            --
    Total                                34           7.3            36           7.6             6            .8
                                         ==           ===            ==           ===             =            ==
</TABLE>

Office Space

HPI leases office space in Denver,  Colorado under a lease which expires in June
1999, for  approximately  $600,000 per year.  During  February 1999, HPI entered
into another  office lease for  approximately  $600,000 per year.  The new lease
commences  upon  occupancy,  which is expected  to be in June or July 1999,  and
terminates in seven and one-half  years.  The lease payments are included in the
allocation of general and  administrative  expenses to HEP and other  affiliated
entities. HEP is guarantor of 60% of the lease obligation, and HCRC is guarantor
of the remaining 40% of the obligation.


ITEM 3 - LEGAL PROCEEDINGS

See Notes 13 and 14 to the financial  statements  included in Item 8 - Financial
Statements and Supplementary Data.


ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No  matters  were  submitted  to a vote of  security  holders  during the fourth
quarter of 1998.



                                     PART II


ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS

HEP's Class A Units are traded on the American Stock  Exchange (the  "Exchange")
under the  symbol  "HEP." As of March 24,  1999,  10,011,852  Class A Units were
outstanding,  held by  approximately  18,386  unitholders  of record and 143,773
Class B Units were  outstanding,  held by Hallwood Group.  The Class B Units are
not publicly traded.  The following table sets forth, for the periods indicated,
the high and low reported  sales prices for the Class A Units as reported on the
Exchange  and the  distributions  paid per  Class A Unit  for the  corresponding
periods.


<PAGE>
<TABLE>
<CAPTION>



Class A Units                                High                  Low             Distributions

<S>                                        <C>                 <C>                     <C>  
First quarter 1997                         $ 10  3/4           $ 8    1/16             $ .13
Second quarter 1997                           9                  7    1/8                .13
Third quarter 1997                            8 15/16            6   15/16               .13
Fourth quarter 1997                          10  1/4             7    1/2                .13
                                                                                        ----
                                                                                       $ .52

First quarter 1998                         $  8 5/8            $ 6    3/8              $ .13
Second quarter 1998                           7                  6                       .13
Third quarter 1998                            7                  4   11/16               .13
Fourth quarter 1998                           5 7/8              3                       .13
                                                                                        ----
                                                                                       $ .52
</TABLE>

On January 17, 1996, HEP's Class C Units began trading on the Exchange under the
symbol  "HEPC." On  February  17,  1998,  HEP closed its public  offering of 1.8
million  Class C Units  which were  priced at $10.00  per Unit.  As of March 24,
1999,  2,464,063 Class C Units were  outstanding,  held by approximately  13,822
unitholders  of  record.  The  following  table  sets  forth,  for  the  periods
indicated,  the high and low  reported  sales  prices  for the  Class C Units as
reported  on the  Exchange  and  distributions  paid  per  Class C Unit  for the
corresponding periods.
<TABLE>
<CAPTION>

Class C Units                                High                  Low             Distributions

<S>                                        <C>                 <C>      >             <C>   
First quarter 1997                         $ 10                $ 8    5/8             $  .25
Second quarter 1997                           9 3/8              8    3/4                .25
Third quarter 1997                           10 1/2              8    7/8                .25
Fourth quarter 1997                          14 7/8             10                       .25
                                                                                       -----
                                                                                       $1.00

First quarter 1998                         $ 11                $ 9   1/8              $  .25
Second quarter 1998                           9 13/16            8   3/8                 .25
Third quarter 1998                            8 1/2              6   3/4                 .25
Fourth quarter 1998                           7 15/16            5   7/8                 .25
                                                                                       -----
                                                                                       $1.00
</TABLE>

HEP's debt agreements  limit aggregate  distributions  paid by HEP in any twelve
month period to 50% of cash flow from operations  before working capital changes
and 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 and 65% of  distributions  received  from  affiliates,  if the principal
amount of debt is less than 50% of the borrowing base.



<PAGE>


ITEM 6 - SELECTED FINANCIAL DATA

The following table sets forth selected financial data regarding HEP's financial
position and results of operations as of the dates indicated. As a result of the
issuance of Class A Units in connection with a litigation  settlement,  all Unit
and per Unit  information  for  periods  prior  to  December  31,  1995 has been
retroactively restated.
<TABLE>
<CAPTION>

                                                       As of and For the Year Ended December 31,
                                                       -----------------------------------------
                                          1998            1997           1996             1995           1994
                                         ------          ------         -------          ------         -----
                         (In thousands except per Unit)

Summary of Operations
<S>                                    <C>              <C>             <C>            <C>             <C>      
   Oil and gas revenues and
     pipeline operations               $  43,177        $  44,707       $  50,644      $  43,454       $  43,899
   Total revenue                          43,586           45,103          51,066         43,780          44,482
   Production operating expense           12,175           11,060          11,511         11,298          12,177
   Depreciation, depletion and
     amortization                         15,720           11,961          13,500         15,827          18,168
   Impairment                             14,000                                          10,943           7,345
   General and administrative
     expense                               5,045            5,333           4,540          5,580           5,630
   Net income (loss)                     (13,895)          12,803          15,726         (9,031)        (10,093)
   Basic net income (loss) per
     Class A and Class B Unit              (1.86)            1.09            1.35          (1.07)          (1.20)
   Diluted net income (loss) per
     Class A and Class B Unit              (1.86)            1.07            1.35          (1.07)          (1.20)
   Distributions per Class A Unit            .52              .52             .52            .80             .80
   Distributions per Class B Unit                                                            .80             .80

Balance Sheet
   Working capital deficit             $  (8,722)       $    (973)      $  (1,355)     $  (4,363)    $    (9,390)
   Property, plant and equipment,
     net                                 105,005           94,331          88,549         94,926         107,414
   Total assets                          139,091          131,603         122,792        125,152         136,281
   Long-term debt                         40,381           34,986          29,461         37,557          25,898
   Long-term contract settlement
     obligation                                                             2,512          2,397           2,666
   Deferred liability                      1,050            1,180           1,533          1,718           1,931
   Minority interest in affiliates         2,788            3,258           3,336          3,042           2,923
   Partners' capital                      62,632           69,064          64,215         57,572          78,803
</TABLE>




<PAGE>


ITEM 7     - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
              RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES

During  1998,  HEP had a net loss of  $13,895,000,  compared  to net  income  of
$12,803,000  for 1997. The 1998 period  includes  noncash charges in the second,
third and fourth quarters  totaling  $14,000,000 for property  impairments which
were taken to lower the capitalized  cost of HEP's properties to an amount equal
to the present value, discounted at 10%, of the future net revenues attributable
to those  properties.  Also  included  in the net loss is a  noncash  charge  of
$4,888,000  which  represents  HEP's equity in the loss of HCRC.  This amount is
largely comprised of HEP's share of HCRC's property impairments.

HEP's  1998  property   impairments  were  recorded  pursuant  to  ceiling  test
limitations  required by the  Securities  and Exchange  Commission for companies
using the full cost method of  accounting.  The total  impairment  was primarily
attributable  to the decline in  commodity  prices and the  write-off of certain
unproved acreage.

The weighted  average  prices  received by HEP for oil and gas have  declined in
each of the last four quarters. HEP's hedges mitigated the price reductions,  by
increasing both the average oil and gas prices by 6%. HEP's weighted average oil
and gas prices,  when the effects of hedging  are  considered,  were 28% and 13%
lower, respectively, for 1998 compared to 1997.

Although  HEP's  production  for 1998 was 14% greater  than the prior year,  and
operating, general and administrative and interest expenses were lower on a unit
of production  basis,  net income was lower because of low commodity  prices and
costs associated with the resolution of litigation.

In December 1998, HEP announced a proposal to consolidate  HEP with HCRC and the
energy interests of Hallwood
Group  into  a  new  corporation   called  Hallwood  Energy   Corporation.   The
consolidation  proposal  was  approved by the Board of Directors of HCRC and the
general  partner of HEP in December 1998.  Because of the larger size of the new
corporation,  HEP anticipates that the new company will have the ability to take
advantage of opportunities  that are unavailable to smaller entities such as HEP
and will have a better ability to raise  capital.  Hallwood  Energy  Corporation
will  focus  on  reserve  growth.  A Joint  Proxy  Statement/Prospectus  for the
consolidation was filed with the Securities  Exchange Commission on December 30,
1998 and is proceeding  through the usual SEC comment  process.  It is presently
anticipated  that  the  Joint  Proxy  Statement/Prospectus  will  be  mailed  to
unitholders of HEP and shareholders of HCRC in April and that the  consolidation
will be  concluded in May 1999.  There can be no  assurance,  however,  that all
conditions to the consolidation will be satisfied by that time.

Liquidity and Capital Resources

Cash Flow

HEP generated $26,277,000 of cash flow from operating activities during 1998.

   The other primary cash inflows were:

   o  Proceeds from long-term debt of $33,000,000;

   o  Proceeds from the issuance of Class C Units, net of syndication costs of
      $16,518,000;

   o  Distributions received from affiliate of $1,583,000;

   o  Proceeds from the sale of property of $454,000;

   o  Exercise of Unit Options of $199,000; and

   o Capital contribution from the general partner of $171,000.



<PAGE>


   Cash was used primarily for:

   o  Additions to property, exploration and development costs of $40,936,000;

   o  Payments of long-term debt of $18,286,000;

   o  Distributions to partners of $9,495,000; and

   o  Payment of contract settlement of $2,767,000.

When combined with miscellaneous other cash activity during the year, the result
was an increase in HEP's cash and cash equivalents of $5,252,000 from $6,622,000
at December 31, 1997 to $11,874,000 at December 31, 1998.

Property Purchases, Sales and Capital Budget

In 1998, HEP incurred  $40,936,000 in direct  property  additions,  development,
exploitation and exploration  costs. The costs were comprised of $28,756,000 for
property acquisitions and approximately $12,180,000 for domestic exploration and
development.  HEP's  1998  capital  program  led to the  replacement,  including
revisions  to prior  year  reserves,  of 72% of 1998  production.  This  reserve
replacement  figure is calculated  using year-end prices of $10.00 per barrel of
oil and $1.90 per mcf of gas. If five-year  average prices of $16.75 per bbl and
$1.86 per mcf are used, HEP replaced 136% of 1998 production.

In the Greater Permian  Region,  HEP expended  $8,385,000  acquiring oil and gas
properties,  including interests in approximately 570 wells, numerous proven and
unproven  drilling  locations,   exploration  acreage,  and  3-D  seismic  data.
Additionally,  HEP spent  approximately  $886,000  to  recomplete  or drill nine
producing  development  wells  and  one  unsuccessful  exploration  well  in the
Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties,  New Mexico. Also,
approximately  $975,000  was  spent  to  drill  11  exploration  wells  and  one
development  well,  nine of which  were  completed  in the Merkle  Project.  HEP
incurred  approximately  $420,000  drilling  three  exploration  wells  and  one
development well in the Griffin area, all of which were unsuccessful.

In the Gulf Coast Region, HEP spent approximately $430,000 for land and $941,000
to drill one Mirasoles project exploration well in Kenedy County, Texas which is
currently in the completion phase. HEP incurred  approximately $365,000 to drill
one successful exploration well in LaVaca County, Texas.  Approximately $375,000
was incurred by HEP for land and leasehold costs and an additional  $615,000 for
costs  associated with drilling one successful  exploration well in Bell County,
Texas.  1998 costs relating to the East Smith Point project in Chambers  County,
Texas were  approximately  $426,000 for land and geologic and geophysical  data,
and an additional  $305,000 to drill one  unsuccessful  exploration  well in the
area.  Approximately  $550,000 was incurred in 1998 by HEP to drill one well now
plugged  and  abandoned  as part  of the  Bison  project  in  Lafayette  Parish,
Louisiana,  and  approximately  $600,000 for plugging costs  associated with two
nonoperated near shore platform wells in the Whitewater Field.

HEP's  significant  property  acquisition  in  the  Rocky  Mountain  Region  was
approximately $17,291,000 for the purchase of a volumetric production payment in
the Colorado San Juan Basin.  Additionally,  HEP's  significant  exploration and
development  expenditures in the Rocky Mountain  Region  included  approximately
$1,028,000 to expand a New Mexico gathering  system;  approximately  $120,000 to
complete  a  successful  exploration  well  within the Cajon Lake Field in Utah;
approximately  $390,000 to drill three  successful wells in the Colorado Western
Slope area;  approximately $245,000 to drill an unsuccessful exploration well in
the West  Sioux area of  Montana;  and  approximately  $728,000  to drill  three
horizontal wells in Toole County Montana, two of which were successful.

See  Item 2 -  Properties,  for  further  discussion  of HEP's  exploration  and
development projects.

Long-lived  assets,  other  than  oil  and gas  properties,  are  evaluated  for
impairment  whenever  events  or  changes  in  circumstances  indicate  that the
carrying  amount  may not be  recoverable.  To  date,  the  Partnership  has not
recognized  any  impairment  losses on long-lived  assets other than oil and gas
properties.


<PAGE>


Distributions

During 1998, HEP declared  distributions  of $.52 per Class A Unit and $1.00 per
Class  C Unit  to its  Unitholders.  Distributions  on the  Class  B  Units  are
suspended  if the  Class A Units  receive a  distribution  of less than $.20 per
Class A Unit per calendar  quarter.  In any quarter for which  distributions  of
$.20 or more  per unit are made on the  Class A  Units,  the  Class B Units  are
entitled to be paid, in whole or in part, suspended  distributions.  The Class C
Units have a distribution preference of $1.00 per year, payable quarterly, which
began  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.

The Board of Directors of HEP's General Partner is considering the  distribution
level for future  quarters,  taking into account oil and gas prices,  cash flow,
long-term debt and borrowing base levels, and the capital needs of HEP.

Unit Option Plans

On January 31, 1995, the Board of Directors of the general partner  approved the
adoption of the 1995 Class A Unit 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-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. As
of December 31, 1998, 34,600 options have been exercised.

During  the second  quarter  of 1998,  HEP  adopted a Class C Unit  Option  Plan
covering  120,000  Class C Units.  Options  to  purchase  all of the Units  were
granted effective May 5, 1998 at an exercise price of $10.00 per Unit, which was
equal to the fair  market  value of the Units on the date of grant.  One-half of
the options  vested on the date of grant,  and the  remainder  vest on the first
anniversary of the date of grant.  As of December 31, 1998, no options have been
exercised.

On May 5, 1998,  HEP  granted  options to  purchase  25,500  Class A Units at an
exercise  price of $6.625 per Unit,  which was equal to the fair market value of
the Units on the date of grant.  These  options  were not granted  pursuant to a
previously  existing plan but are subject to terms and  conditions  identical to
those in HEP's 1995 Unit Option  Plan.  One-third  of the options  vested on the
date of grant,  and the remainder vest one-half on the first  anniversary of the
date of grant and one-half on the second anniversary of the date of grant. As of
December 31, 1998, no options have been exercised.

During 1996,  HEP 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 only provisions of SFAS 123, the
adoption of SFAS 123 did not have a material effect on the financial position or
results of operations of HEP.

Financing

During the first  quarter of 1997,  HEP and its  lenders  amended  HEP's  Second
Amended and Restated Credit  Agreement (as amended,  the "Credit  Agreement") to
extend the term date of its Credit  Agreement to May 31,  1999.  The lenders are
Morgan  Guaranty  Trust Company,  First Union  National Bank and  NationsBank of
Texas. Under the Credit Agreement, HEP has a borrowing base of $62,000,000.  HEP
had amounts  outstanding  at  December  31, 1998 of  $49,700,000.  HEP's  unused
borrowing base totaled $12,300,000 at March 24, 1999.

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
7.125% at  December  31,  1998.  Interest  is  payable  monthly,  and  quarterly
principal payments of $3,106,500 commence May 31, 1999.



<PAGE>


The borrowing base for the Credit  Agreement is redetermined  semiannually,  and
the next  redetermination  is  scheduled  for the second  quarter  of 1999.  HEP
anticipates that, because of low oil and gas prices, its lenders will reduce the
borrowing base. HEP does not anticipate that a reduced  borrowing base will have
a material  adverse effect.  The Credit  Agreement is secured by a first lien on
approximately  80% in  value  of  HEP's  oil and gas  properties.  Additionally,
aggregate  distributions  which  may be paid by HEP in any 12 month  period  are
limited to 50% of cash flow from  operations  before working capital changes and
distributions  received from affiliates,  if the principal amount of debt of HEP
is 50% or more of the borrowing base. Aggregate  distributions which may be paid
by HEP are limited to 65% of cash flow from  operations  before working  capital
changes and 65% of distributions  which may be received from affiliates,  if the
principal amount of debt is less than 50% of the borrowing base.

As a part of its risk management  strategy,  HEP enters into financial contracts
to  hedge  the  interest  payments  related  to a  portion  of  its  outstanding
borrowings under its Credit  Agreement.  HEP does not use the hedges for trading
purposes,  but rather to protect against the variability of the cash flows under
its Credit  Agreement,  which has a floating interest rate. The amounts received
or paid upon settlement of these transactions are recognized as interest expense
at the time the interest payments are due.

As  of  March  24,  1999,   HEP  was  a  party  to  six  contracts   with  three
counterparties.  The  following  table  provides  a summary  of HEP's  financial
contracts.

                                                  Average
                           Amount of              Contract
      Period              Debt Hedged            Floor Rate

1999                      $27,000,000                5.70%
2000                       30,000,000                5.65%
2001                       24,000,000                5.23%
2002                       25,000,000                5.23%
2003                       25,000,000                5.23%
2004                        4,000,000                5.23%

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 or repaid at a future date.

As of December 31,  1998,  HEP had a net  over-produced  position of 157,000 mcf
($298,000 valued at year-end gas prices). The general partner believes that this
imbalance can be made up from  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.  The reserves  disclosed in Item 8 have been decreased by 157,000 mcf
in order to reflect HEP's gas balancing position.

Recently Issued Accounting Pronouncements

In June 1997,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting Standards No. 130 "Reporting  Comprehensive  Income" (SFAS
130"). SFAS 130 establishes standards for reporting and display of comprehensive
income and its components (revenues,  expenses, gains, and losses) in a full set
of general purpose financial  statements.  SFAS 130 requires that all items that
are  required to be  recognized  under  accounting  standards as  components  of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods  provided for  comparative  purposes is required.
The Partnership  adopted SFAS 130 on January 1, 1998. The  Partnership  does not
have any items of other  comprehensive  income for the years ended  December 31,
1998, 1997 and 1996. Therefore, total comprehensive income (loss) is the same as
net income (loss) for those periods.


<PAGE>


In June 1997,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting  Standards  No.  131  "Disclosures  about  Segments  of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards
for  reporting  selected   information  about  operating  segments  and  related
disclosures about products and services,  geographic areas, and major customers.
SFAS 131 requires that an entity report  financial and  descriptive  information
about  its  operating  segments  which  are  regularly  evaluated  by the  chief
operating  decision maker in deciding how to allocate resources and in assessing
performance. HEP adopted FAS 131 in 1998.

The Partnership engages in the development,  production and sale of oil and gas,
and the  acquisition,  exploration,  development  and  operation  of oil and gas
properties in the  continental  United States.  In addition,  the  Partnership's
activities  exhibit  similar  economic  characteristics  and  involve  the  same
products, production processes, class of customers, and methods of distribution.
Management of the  Partnership  evaluates its performance as a whole rather than
by product  or  geographically.  As a result,  HEP's  operations  consist of one
reportable segment.

In June 1998,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting  Standards No. 133 "Accounting for Derivative  Instruments
and  Hedging  Activities"  ("SFAS  133").  SFAS 133  establishes  standards  for
derivative  instruments,  including certain derivative  instruments  embedded in
other  contracts  (collectively  referred  to as  derivatives)  and for  hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities  in the statement of financial  position and measure those
instruments  at fair value.  If certain  conditions are met, a derivative may be
specifically  designated  as (a) a hedge of the  exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted  transaction,  or
(c) a hedge of the foreign  currency  exposure of a net  investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated  forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation.  The Partnership is required to
adopt SFAS 133 on January 1, 2000. The Partnership has not completed the process
of evaluating the impact that will result from adopting SFAS 133.

Cautionary Statement Regarding Forward-Looking Statements

In the interest of providing the partners with certain information regarding the
Partnership's future plans and operations,  certain statements set forth in this
Form 10-K relate to management's  future plans and  objectives.  Such statements
are  forward-looking   statements.   Although  any  forward-looking   statements
contained  in this  Form  10-K or  otherwise  expressed  by or on  behalf of the
Partnership  are,  to the  knowledge  and in the  judgment of the  officers  and
directors  of the  general  partner,  expected  to prove  true and come to pass,
management  is  not  able  to  predict  the  future  with  absolute   certainty.
Forward-looking  statements  involve known and unknown  risks and  uncertainties
which may cause the  Partnership's  actual  performance and financial results in
future periods to differ materially from any projection,  estimate or forecasted
result.

These risks and uncertainties include, among others:

Volatility of oil and gas prices. It is impossible to predict future oil and gas
price  movements with  certainty.  Declines in oil and gas prices may materially
adversely  affect  HEP's  financial  condition,  liquidity,  ability  to finance
planned capital expenditures and results of operations. Lower oil and gas prices
may also reduce the amount of oil and gas that HEP can produce economically.

HEP's  revenues,  profitability,  future  growth and ability to borrow  funds or
obtain additional capital, as well as the carrying value of its properties, will
be substantially  dependent upon prevailing prices of oil and gas. Historically,
the markets for oil and gas have been volatile,  and they 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 HEP's control.


<PAGE>


Competition from larger, more established oil and gas companies.  HEP encounters
competition  from  other oil and gas  companies  in all areas of its  operation,
including the acquisition of exploratory prospects and proven properties.  HEP'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 HEP's and, in many
instances,  have been engaged in the oil and gas business for a much longer time
than HEP. 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 HEP's  financial
or human  resources  permit.  HEP'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.

Risks of drilling  activities.  HEP's success will be materially  dependent upon
the continued success of its drilling program.  HEP's future drilling activities
may not be successful and, if drilling activities are unsuccessful, such failure
will have an adverse  effect on HEP's future results of operations and financial
condition. 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.  Although  HEP 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.

Risks  relating to the  acquisition  of oil and gas  properties.  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, HEP will perform a review of the subject properties that it believes
to be generally  consistent  with  industry  practices.  This  usually  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 all or part of these problems.  There
can be no assurances that any  acquisition of property  interests by HEP will be
successful  and, if an  acquisition is  unsuccessful,  that the failure will not
have an adverse  effect on HEP's  future  results of  operations  and  financial
condition.

Hazards  relating  to well  operations  and lack of  insurance.  The oil and gas
business involves certain hazards such as well blowouts; craterings; explosions;
uncontrollable flows of oil, gas or well fluids; fires; formations with abnormal
pressures;  pollution;  and releases of toxic gas or other environmental hazards
and risks, any of which could result in substantial  losses to HEP. In addition,
HEP may be  liable  for  environmental  damages  caused  by  previous  owners of
property  purchased or leased by HEP. 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 HEP's properties.  While HEP believes that
it  maintains  all types of  insurance  commonly  maintained  in the oil and gas
industry, it does not maintain business interruption insurance. In addition, HEP
cannot  predict with  certainty the  circumstances  under which an insurer might
deny coverage.  The occurrence of an event not fully covered by insurance  could
have a materially  adverse  effect on HEP's  financial  condition and results of
operations.



<PAGE>


Future oil and gas  production  depends on  continually  replacing and expanding
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.  HEP's future oil and gas production is,  therefore,
highly  dependent  upon its  ability to  economically  find,  develop or acquire
additional reserves in commercial quantities.  Except to the extent HEP acquires
properties  containing  proved reserves or conducts  successful  exploration and
development  activities,  or both,  the proved  reserves of HEP will  decline as
reserves are produced.  The business of exploring  for,  developing or acquiring
reserves  is  capital-intensive.  To the  extent  cash flow from  operations  is
reduced,  and external reserves of capital become limited or unavailable,  HEP's
ability to make the  necessary  capital  investments  to  maintain or expand its
asset base of oil and gas reserves would be impaired. In addition,  there can be
no  assurance  that  HEP's  future  exploration,   development  and  acquisition
activities will result in additional proved reserves or that HEP will be able to
drill productive wells at acceptable costs. Furthermore, although HEP's revenues
could  increase if  prevailing  prices for oil and gas  increase  significantly,
HEP's finding and development costs could also increase.

Estimates of reserves and future cash flows are imprecise. Reservoir engineering
is a subjective process of estimating  underground  accumulations 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  from them
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.  In addition,  the status
of the  exploration  and  development  program  of any oil and  gas  company  is
ever-changing.  Consequently,  reserve  estimates  also vary over  time.  Actual
production, revenues and expenditures with respect to HEP's reserves will likely
vary from estimates, and such variances may be material.

Inflation and Changing Prices

Prices obtained for oil and gas production depend upon numerous factors that are
beyond  the  control  of HEP,  including  the  extent of  domestic  and  foreign
production,  imports of foreign  oil,  market  demand,  domestic  and  worldwide
economic and political conditions,  storage capacity and government  regulations
and tax laws.  Prices  for both oil and gas have  fluctuated  from 1996  through
1998, with a distinct downward trend in both oil and gas prices occurring in the
calendar year 1998. HEP anticipates that both oil and gas prices will remain low
throughout  1999.  In preparing  its 1999  budget,  HEP has  estimated  that the
weighted  average oil price (for  barrels not hedged) will be $11.00 per barrel,
and the weighted average price of natural gas (for mcf not hedged) will be $1.70
per mcf for the year. There can be no assurance that HEP's forecast is accurate.
If prices  decrease  further,  it can be expected that the results of operations
and cash flow will be affected, and HEP's capital budget will decrease.

The following  table presents the weighted  average prices  received per year by
HEP, and the effects of the hedging transactions discussed below.
<TABLE>
<CAPTION>

                         Oil                       Oil                        Gas                       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>  
1998                    $12.82                    $13.65                     $1.99                     $2.02
1997                     19.35                     19.08                      2.54                      2.31
1996                     20.85                     20.10                      2.38                      2.24

</TABLE>


<PAGE>


As part of its risk management strategy,  HEP enters into financial contracts to
hedge the price of its oil and  natural  gas.  The  purpose  of the hedges is to
provide protection against price decreases and to provide a measure of stability
in the volatile  environment  of oil and natural gas spot  pricing.  The amounts
received or paid upon settlement of hedge contracts are recognized as oil or gas
revenue at the time the hedged volumes are sold.  During 1998, HEP did not enter
into  additional  oil price hedges for future years because  hedge  contracts at
prices HEP considers advantageous are not available.

The  financial  contracts  used by HEP to hedge the price of its oil and natural
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.  As of March 24,
1999,  HEP  was  a  party  to  26  financial   contracts  with  three  different
counterparties.

The following table provides a summary of HEP's financial contracts.

                                 Oil
                              Percent of
                              Production               Contract
      Period                    Hedged                Floor Price
                                                       (per bbl)

     1999                           2%                  $14.88

All of the oil volumes hedged are subject to a  participating  hedge 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 25% of the difference
between the contract  price and the posted  futures price if the posted  futures
price is greater than the contract price.  All of the volumes hedged are subject
to a collar  agreement  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 $16.50 to $18.35 per
barrel.



<PAGE>


                                 Gas
                              Percent of
                              Production               Contract
      Period                    Hedged                Floor Price
                                                       (per mcf)

     1999                         45%                     $2.02
     2000                         42%                     $2.07
     2001                         38%                     $2.04
     2002                         30%                     $2.09

Between  15% and 25% of the gas  volumes  hedged in each year are  subject  to a
collar  agreement  whereby HEP will receive the contract price if the spot price
is lower than the contract price, the cap price is 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 $2.63 per mcf to $2.80 per mcf.

During the first quarter through March 24, 1999, the weighted  average oil price
(for barrels not hedged) was approximately  $10.95 per barrel,  and the weighted
average  price of natural gas (for mcf not hedged) was  approximately  $1.65 per
mcf.

Inflation

Inflation  did not have a material  impact on HEP in 1998,  1997 and 1996 and is
not anticipated to have a material impact in 1999.



<PAGE>


Results of Operations

The  following  tables are  presented  to contrast  HEP's  revenue,  expense and
earnings for discussion purposes.  Significant fluctuations are discussed in the
accompanying  narrative.  The "direct  owned"  column  represents  HEP's  direct
royalty and  working  interests  in oil and gas  properties.  The "Mays"  column
represents the results of operations of six May Limited  Partnerships  which are
consolidated  with HEP. In 1998, HEP owned  interests which ranged from 54.8% to
69.1% of the Mays;  in 1997 HEP's  ownership  in the Mays  ranged  from 54.7% to
68.7%, and in 1996 HEP's ownership in the Mays ranged from 54.5% to 68.5%.


<PAGE>
<TABLE>
<CAPTION>


                                            TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
                                                      (In thousands except price)


                                           For the Year Ended December 31, 1998             For the Year Ended December 31, 1997
                                           ------------------------------------             ------------------------------------
                                               Direct                                    Direct
                                               Owned       Mays       Total              Owned             Mays            Total

<S>                                          <C>        <C>         <C>                <C>              <C>              <C>   
Gas production (mcf)                           12,893     1,144       14,037             10,426           1,348            11,774
Oil production (bbl)                              735        52          787                691              79               770

Average gas price                             $  1.99   $  2.38       $ 2.02           $   2.23        $   2.91          $   2.31
Average oil price                             $ 13.69   $ 13.04      $ 13.65            $ 18.94         $ 20.27           $ 19.08

Gas revenue                                  $ 25,643    $2,723     $ 28,366            $23,302          $3,918           $27,220
Oil revenue                                    10,063       678       10,741             13,089           1,601            14,690
Pipeline and other revenue                      4,070                  4,070              2,797                             2,797
Interest income                                   346        63          409                324              72               396
                                             --------   -------     --------           --------         -------          --------

     Total revenue                             40,122     3,464       43,586             39,512           5,591            45,103
                                              -------     -----      -------             ------           -----            ------

Production operating                           11,740       435       12,175             10,498             562            11,060
Facilities operating                              498                    498                641                               641
General and administrative                      4,671       374        5,045              4,953             380             5,333
Depreciation, depletion, and amortization      14,500     1,220       15,720             10,630           1,331            11,961
Impairment of oil and gas properties           14,000                 14,000
Interest                                        2,797                  2,797              3,096                             3,096
Equity in (income) loss of HCRC                 4,888                  4,888             (1,348)                           (1,348)
Minority interest                                           976          976                              1,797             1,797
Litigation                                      1,382                  1,382               (234)             (6)             (240)
                                             -------- ---------     --------            -------         -------           --------

     Total expense                             54,476     3,005       57,481             28,236           4,064            32,300
                                              -------     -----      -------             ------           -----            ------

       Net income (loss)                     $(14,354) $    459     $(13,895)           $11,276          $1,527           $12,803
                                               ======   =======       ======             ======           =====            ======
</TABLE>



<PAGE>

<TABLE>
<CAPTION>

                                            TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
                                                      (In thousands except price)


                                                             For the Year Ended December 31, 1996
                                                     Direct
                                                      Owned                  Mays                   Total

<S>                                                  <C>                     <C>                  <C>   
Gas production (mcf)                                   11,003                  1,783                12,786
Oil production (bbl)                                      862                    110                   972

Average gas price                                    $   2.11               $   3.05              $   2.24
Average oil price                                     $ 19.92                $ 21.52               $ 20.10

Gas revenue                                           $23,178                $ 5,440               $28,618
Oil revenue                                            17,167                  2,367                19,534
Pipeline and other revenue                              2,492                                        2,492
Interest income                                           356                     66                   422
                                                      -------                -------               -------

     Total revenue                                     43,193                  7,873                51,066
                                                       ------                  -----                ------

Production operating                                   10,782                    729                11,511
Facilities operating                                      726                                          726
General and administrative                              4,131                    409                 4,540
Depreciation, depletion, and amortization              11,729                  1,771                13,500
Interest                                                3,878                                        3,878
Equity in income of HCRC                               (1,768)                                       (1,768)
Minority interest                                                              2,723                 2,723
Litigation                                                223                      7                   230
                                                      -------                -------               -------

     Total expense                                     29,701                  5,639                35,340
                                                       ------                  -----                ------

       Net income                                     $13,492                 $2,234               $15,726
                                                       ======                  =====                ======
</TABLE>


<PAGE>


1998 Compared to 1997

Gas Revenue

Gas revenue increased $1,146,000 during 1998 compared with 1997. The increase is
comprised of an increase in gas  production  from  11,774,000 mcf during 1997 to
14,037,000  mcf during 1998,  partially  offset by a decrease in the average gas
price from $2.31 per mcf in 1997 to $2.02 per mcf in 1998.  Production increased
because  two  temporarily  shut-in  wells were back on line.  The two wells were
temporarily  shut-in during the second quarter of 1997 while workover procedures
were  performed.  The increase in gas  production is also due to an expansion of
the gathering system in San Juan County, New Mexico during 1998.

The effect of HEP's  hedging  transactions  as described  under  "Inflation  and
Changing  Prices" was to increase  HEP's average gas price from $1.99 per mcf to
$2.02 per mcf, representing a $421,000 increase in gas revenues for 1998.

Oil Revenue

Oil revenue decreased $3,949,000 during 1998 compared with 1997. The decrease is
comprised  of a decrease in the average oil price from $19.08 per barrel in 1997
to $13.65 per barrel in 1998,  partially  offset by an increase  in  production,
from 770,000  barrels in 1997 to 787,000 barrels in 1998.  Production  increased
slightly because two temporarily  shut-in wells were back on line. The two wells
were  temporarily  shut-in  during  the second  quarter  of 1997 while  workover
procedures  were  performed.  The  production  increase was partially  offset by
normal production declines.

The effect of HEP's hedging transactions was to increase HEP's average oil price
from $12.82 per barrel to $13.65 per barrel, resulting in a $653,000 increase in
oil revenue for 1998.

Pipeline and Other

Pipeline and other  revenue  consists  primarily of  facilities  income from two
gathering  systems  located  in New  Mexico,  revenues  derived  from salt water
disposal and incentive payments related to certain wells in San Juan County, New
Mexico.  Pipeline facilities and other revenue increased  $1,273,000 during 1998
compared  with 1997  primarily  due to an increase in incentive  payment  income
resulting from HEP's acquisition of a volumetric  production  payment during May
1998.

Interest Income

The  increase  in interest  income of $13,000  during  1998  compared  with 1997
resulted from a higher average cash balance during 1998 compared with 1997.

Production Operating Expense

Production  operating  expense  increased  $1,115,000  during 1998 compared with
1997.  The  increase is due to  increased  operating  costs  resulting  from the
drilling  projects  completed  during 1997 as well as the  additional  operating
expenses related to the properties  acquired in the Arcadia  acquisition  during
October 1998.

Facilities Operating Expense

Facilities  operating  expense  represents  operating  expenses  associated with
various smaller  gathering  systems operating by HEP. The decrease in facilities
operating expense of $143,000 is primarily due to decreased maintenance activity
during 1998 compared with 1997.



<PAGE>


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 the operating company on behalf of HEP.
These expenses  decreased  $288,000 during 1998 compared with 1997 primarily due
to a decrease in performance based compensation during 1998.

Depreciation, Depletion and Amortization Expense

Depreciation,  depletion and amortization  expense  increased  $3,759,000 during
1998  compared  with  1997.  The  increase  is due to a  higher  depletion  rate
resulting  from the  increased  production  discussed  above  as well as  higher
capitalized costs during 1998.

Impairment of Oil and Gas Properties

Impairment  of oil  and gas  properties  during  1998  represents  the  property
impairments  recorded during 1998 because capitalized costs exceeded the present
value  (discounted at 10%) of estimated  future net revenues from proved oil and
gas reserves at June 30, 1998,  September 30, 1998 and December 31, 1998,  based
on prices of $13.00 per  barrel of oil and $2.00 per mcf of gas,  $12.80 per bbl
of oil and $1.90 per mcf of gas and  $10.00  per bbl of oil and $1.90 per mcf of
gas, respectively.

Interest Expense

Interest  expense  decreased  $299,000  during 1998 as compared  with 1997.  The
decrease  is due to a lower  average  outstanding  debt  balance  during 1998 as
compared to 1997.

Equity in Earnings (Loss) of HCRC

Equity  in  earnings  (loss)  of  HCRC  represents  HEP's  share  of its  equity
investment in HCRC. HEP's equity in HCRC's earnings decreased  $6,236,000 during
1998 as  compared to 1997.  The  decrease  is  primarily  the result of property
impairments recorded by HCRC during 1998.

Minority Interest in Net Income of Affiliates

Minority interest in net income of affiliates represents  unaffiliated partners'
interest in the net income of the May Partnerships.  The decrease of $821,000 is
due to a decrease in the net income of the May Partnerships  resulting primarily
from lower oil and gas prices and decreased production from their properties.

Litigation

Litigation  expense during 1998 includes the settlement of the Ellender  lawsuit
described in Item 8, Note 14, and the costs  related to the Arcadia  arbitration
described  in Item 8, Note 13.  Litigation  income  during 1997 is  comprised of
insurance  proceeds  which  reimbursed a portion of expense  incurred in a prior
period to settle certain litigation.

1997 Compared to 1996

Gas Revenue

Gas revenue  decreased  by  $1,398,000  during 1997 as compared  with 1996.  The
decrease is comprised of a decrease in gas production from 12,786,000 mcf during
1996 to  11,774,000  mcf during  1997,  partially  offset by an  increase in the
average  gas price  from  $2.24  per mcf in 1996 to $2.31  per mcf in 1997.  The
decrease in production is due to the temporary shut-in of two wells in Louisiana
during the second quarter of 1997 while workover  procedures  were performed and
to normal production declines.



<PAGE>


The effect of HEP's  hedging  transactions  as described  under  "Inflation  and
Changing  Prices" was to decrease  HEP's average gas price from $2.54 per mcf to
$2.31 per mcf, representing a $2,708,000 decrease in gas revenues for 1997.

Oil Revenue

Oil revenue decreased $4,844,000 during 1997 as compared with 1996. The decrease
is  comprised  of a decrease  in the average oil price from $20.10 per barrel in
1996 to $19.08 per barrel in 1997,  and a decrease in  production,  from 972,000
barrels in 1996 to 770,000 barrels in 1997. The decrease in production is due to
the  temporary  shut-in of two wells in Louisiana  during the second  quarter of
1997 while workover procedures were performed and to normal production declines.

The effect of HEP's hedging transactions described under "Inflation and Changing
Prices" was to decrease HEP's average oil price from $19.35 per barrel to $19.08
per barrel, resulting in a $208,000 decrease in oil revenue for 1997.

Pipeline and Other

Pipeline and other revenue increased  $305,000 during 1997 as compared with 1996
primarily due to increased salt water disposal income.

Interest Income

The  decrease in interest  income of $26,000  during 1997 as compared  with 1996
resulted from a lower average cash balance during 1997 as compared with 1996.

Production Operating Expense

Production  operating  expense  decreased  $451,000 during 1997 as compared with
1996,  primarily  as a  result  of  decreased  production  taxes  due to the 13%
decrease in oil and gas revenue during 1997 discussed above.

Facilities Operating Expense

The decrease in  facilities  operating  expense of $85,000 is  primarily  due to
decreased maintenance activity during 1997 as compared with 1996.

General and Administrative Expense

General and  administrative  expense increased  $793,000 during 1997 as compared
with 1996 primarily due to an increase in performance based  compensation and an
increase  in bank fees due to the  extension  of the term date of HEP's  line of
credit during 1997.

Depreciation, Depletion and Amortization Expense

Depreciation,  depletion and amortization  expense  decreased  $1,539,000 during
1997 as compared  with 1996.  The  decrease is  primarily  the result of a lower
depletion  rate  in 1997 as  compared  with  1996,  due to the 13%  decrease  in
production discussed above.

Interest Expense

Interest  expense  decreased  $782,000  during 1997 as compared  with 1996.  The
decrease  is due to a lower  average  outstanding  debt  balance  during 1997 as
compared to 1996.



<PAGE>


Equity in Earnings  (Loss) of HCRC

HEP's  equity  in HCRC's  earnings  (loss)  decreased  $420,000  during  1997 as
compared  to 1996.  The  decrease is  primarily  the result of lower oil and gas
revenues  during  1997  caused   primarily  by  HCRC's  decreased  oil  and  gas
production.

Minority Interest in Net Income of Affiliates

Minority interest in net income of affiliates represents  unaffiliated partners'
interest in the net income of the May Partnerships.  The decrease of $926,000 is
due to a decrease in the net income of the May Partnerships  resulting primarily
from decreased production from their properties.

Litigation

Litigation  settlement  income  during 1997 is comprised  of insurance  proceeds
which  reimbursed  a portion of  expense  incurred  in a prior  period to settle
certain litigation. Litigation settlement expense during 1996 consists primarily
of expenses incurred to settle various individually insignificant claims against
HEP.


<PAGE>


ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEP's primary market risks relate to changes in interest rates and in the prices
received  from sales of oil and  natural  gas.  HEP's  primary  risk  management
strategy is to partially  mitigate the risk of adverse changes in its cash flows
caused by increases in interest rates on its variable rate debt and decreases in
oil and natural gas prices, by entering into derivative  financial and commodity
instruments,  including swaps,  collars and  participating  commodity hedges. By
hedging only a portion of its market risk exposures,  HEP is able to participate
in the increased  earnings and cash flows  associated with decreases in interest
rates and  increases  in oil and natural gas prices;  however,  it is exposed to
risk on the unhedged  portion of its variable  rate debt and oil and natural gas
production.

Historically,  HEP has  attempted to hedge the exposure  related to its variable
rate debt and its  forecasted oil and natural gas production in amounts which it
believes are prudent  based on the prices of available  derivatives  and, in the
case of production hedges, the Partnership's  deliverable  volumes. HEP attempts
to manage the  exposure  to adverse  changes in the fair value of its fixed rate
debt  agreements by issuing fixed rate debt only when  business  conditions  and
market conditions are favorable.

HEP does not use or hold derivative instruments for trading purposes nor does it
use derivative instruments with leveraged features. HEP's derivative instruments
are designated and effective as hedges against its identified  risks, and do not
of themselves  expose HEP to market risk because any adverse  change in the cash
flows associated with the derivative  instrument is accompanied by an offsetting
change in the cash flows of the hedged transaction.

Notes  1 and 5 to the  financial  statements  provide  further  disclosure  with
respect to derivatives and related accounting policies.

All derivative activity is carried out by personnel who have appropriate skills,
experience and supervision.  The personnel involved in derivative  activity must
follow prescribed  trading limits and parameters that are regularly  reviewed by
the Board of Directors of the general partner and by senior management. HEP uses
only well-known,  conventional derivative instruments and attempts to manage its
credit  risk by entering  into  financial  contracts  with  reputable  financial
institutions.

Following are disclosures  regarding HEP's market risk sensitive  instruments by
major category.  Investors and other users are cautioned to avoid simplistic use
of these  disclosures.  Users should  realize  that the actual  impact of future
interest rate and commodity  price movements will likely differ from the amounts
disclosed  below due to ongoing  changes in risk exposure  levels and concurrent
adjustments  to hedging  positions.  It is not  possible to  accurately  predict
future movements in interest rates and oil and natural gas prices.

Interest  Rate Risks (non  trading) - HEP uses both fixed and variable rate debt
to partially  finance  operations and capital  expenditures.  As of December 31,
1998,  HEP's debt consists of borrowings  under its Credit Agreement which bears
interest at a variable  rate. HEP hedges a portion of the risk  associated  with
this  variable  rate debt  through  derivative  instruments,  which  consist  of
interest rate swaps and collars.  Under the swap  contracts,  HEP makes interest
payments on its Credit  Agreement  as scheduled  and receives or makes  payments
based on the differential between the fixed rate of the swap and a floating rate
plus  a  defined  differential.  These  instruments  reduce  HEP's  exposure  to
increases in interest  rates on the hedged portion of its debt by enabling it to
effectively pay a fixed rate of interest or a rate which only fluctuates  within
a predetermined  ceiling and floor. A hypothetical increase in interest rates of
two  percentage  points  would cause a loss in income and cash flows of $995,000
during 1999,  assuming that  outstanding  borrowings  under the Credit Agreement
remain at current levels.  This loss in income and cash flows would be offset by
a $520,000  increase in income and cash flows  associated with the interest rate
swap and collar agreements that are in effect for 1999.


<PAGE>


Commodity  Price  Risk (non  trading)  - HEP  hedges a portion of the price risk
associated  with the sale of its oil and natural gas production  through the use
of  derivative  commodity  instruments,  which  consist  of swaps,  collars  and
participating  hedges.  These instruments  reduce HEP's exposure to decreases in
oil and natural gas prices on the hedged  portion of its  production by enabling
it to effectively receive a fixed price on its oil and gas sales or a price that
only fluctuates between a predetermined  floor and ceiling.  HEP's participating
hedges also  enable HEP to receive 25% of any  increase in prices over the fixed
prices  specified in the  contracts.  As of March 24, 1999, HEP has entered into
derivative  commodity  hedges covering an aggregate of 16,000 barrels of oil and
18,308,000 mcf of gas that extend through 2002. Under the these  contracts,  HEP
sells its oil and natural 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 amount  received or
paid upon  settlement  of these  contracts is  recognized  as oil or natural gas
revenues at the time the hedged volumes are sold. A hypothetical decrease in oil
and natural gas prices of 10% from the prices in effect as of December  31, 1998
would cause a loss in income and cash flows of $3,800,000 during 1999,  assuming
that oil and gas production remain at 1998 levels.  This loss in income and cash
flows  would be  offset  by a  $1,220,000  increase  in  income  and cash  flows
associated with the oil and natural gas derivative  contracts that are in effect
for 1999.




<PAGE>


ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>

                                         INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                                                                                                           Page No.

FINANCIAL STATEMENTS:

<S>                                                                                                            <C>
Independent Auditors' Report                                                                                     33

Consolidated Balance Sheets at December 31, 1998 and 1997                                                     34-35

Consolidated Statements of Operations for the years ended
   December 31, 1998, 1997 and 1996                                                                              36

Consolidated Statements of Partners' Capital for the years
   ended December 31, 1998, 1997 and 1996                                                                        37

Consolidated Statements of Cash Flows for the years ended
   December 31, 1998, 1997 and 1996                                                                              38

Notes to Consolidated Financial Statements                                                                    39-55

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)                                                      56-59

</TABLE>


<PAGE>


                          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, 1998 and 1997 and for each of the three years
in the period  ended  December  31,  1998,  listed in the index at Item 8. 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, 1998 and 1997, and the results of its operations and its cash flows
for each of the three years in the period ended  December 31, 1998 in conformity
with generally accepted accounting principles.



DELOITTE & TOUCHE LLP

Denver, Colorado
March 24, 1999



<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                                      CONSOLIDATED BALANCE SHEETS
                                                            (In thousands)


                                                                                   December 31,
                                                                          1998                      1997

CURRENT ASSETS
<S>                                                                    <C>                       <C>       
   Cash and cash equivalents                                           $  11,874                 $    6,622
   Accounts receivable:
     Oil and gas revenues                                                  5,911                      8,772
     Trade                                                                 4,040                      5,069
   Due from affiliates                                                       119                        588
   Prepaid expenses and other current assets                               1,338                      1,091
   Net working capital of affiliate                                          236              
                                                                      ----------                   --------
       Total                                                              23,518                     22,142
                                                                        --------                   --------

PROPERTY,  PLANT  AND  EQUIPMENT,  at cost  Oil and gas  properties  (full  cost
   method):
     Proved mineral interests                                            664,799                    624,621
     Unproved mineral interests - domestic                                 2,694                      2,315
   Furniture, fixtures and other                                           3,411                      3,513
                                                                       ---------                  ---------
       Total                                                             670,904                    630,449

   Less accumulated depreciation, depletion,
     amortization and property impairment                               (565,899)                  (536,118)
                                                                         -------                    -------
       Total                                                             105,005                     94,331
                                                                         -------                   --------

OTHER ASSETS
   Investment in common stock of HCRC                                     10,160                     15,048
   Deferred expenses and other assets                                        408                         82
                                                                      ----------                -----------
       Total                                                              10,568                     15,130
                                                                        --------                   --------

TOTAL ASSETS                                                            $139,091                   $131,603
                                                                         =======                    =======



















<FN>

                        (Continued on the following page)
</FN>
</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                                      CONSOLIDATED BALANCE SHEETS
                                                     (In thousands, except Units)


                                                                                        December 31,
                                                                               1998                       1997

CURRENT LIABILITIES
<S>                                                                          <C>                       <C>      
   Accounts payable and accrued liabilities                                  $  22,921                 $  19,915
   Current portion of long-term debt                                             9,319
   Net working capital deficit of affiliate                                                                  448
   Current portion of contract settlement                                                                  2,752
                                                                         -------------                 ---------
       Total                                                                    32,240                    23,115
                                                                              --------                  --------

NONCURRENT LIABILITIES
   Long-term debt                                                               40,381                    34,986
   Deferred liability                                                            1,050                     1,180
                                                                             ---------                 ---------
       Total                                                                    41,431                    36,166
                                                                              --------                  --------

         Total liabilities                                                      73,671                    59,281
                                                                              --------                  --------

MINORITY INTEREST IN AFFILIATES                                                  2,788                     3,258
                                                                             ---------                 ---------

COMMITMENTS AND CONTINGENCIES (NOTE 16)

PARTNERS' CAPITAL
   Class A Units -  10,011,854  and  9,977,254  Units  issued  in 1998 and 1997,
     respectively; 9,121,612 and 9,077,949
     Units outstanding in 1998 and 1997, respectively                           44,198                    66,184
   Class B Subordinated Units - 147,773 Units outstanding
     in 1998 and 1997                                                            1,143                     1,411
   Class C Units - 2,464,063 and 664,063 Units outstanding in
     1998 and 1997, respectively                                                21,386                     4,868
   General Partner                                                               2,814                     3,580
   Treasury Units - 890,242 and 899,305 Units in 1998
     and 1997, respectively                                                      (6,909)                   (6,979)
                                                                              ---------                 ---------
         Partners' capital - net                                                 62,632                    69,064
                                                                               --------                  --------

TOTAL LIABILITIES AND PARTNERS' CAPITAL                                       $139,091                   $131,603
                                                                               =======                    =======













<FN>


               The accompanying notes are an integral part of the
                       consolidated financial statements.
</FN>
</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                                 CONSOLIDATED STATEMENTS OF OPERATIONS
                                                    (In thousands except per Unit)


                                                                          For the Year Ended December 31,
                                                                      1998             1997              1996

REVENUES:
<S>                                                                 <C>              <C>                 <C>     
  Gas revenue                                                       $ 28,366         $ 27,220            $ 28,618
  Oil revenue                                                         10,741           14,690              19,534
  Pipeline and other                                                   4,070            2,797               2,492
  Interest                                                               409              396                 422
                                                                   ---------        ---------            --------
                                                                      43,586           45,103              51,066
                                                                     -------          -------             -------

EXPENSES:
  Production operating                                                12,175           11,060              11,511
  Facilities operating                                                   498              641                 726
  General and administrative                                           5,045            5,333               4,540
  Depreciation, depletion and amortization                            15,720           11,961              13,500
  Impairment of oil and gas properties                                14,000
  Interest                                                             2,797            3,096               3,878
                                                                    --------         --------            --------
                                                                      50,235           32,091              34,155
                                                                     -------          -------             -------

OTHER INCOME (EXPENSES):
  Equity in earnings (loss) of HCRC                                    (4,888)          1,348               1,768
  Minority interest in net income of affiliates                          (976)          (1,797)            (2,723)
  Litigation                                                           (1,382)            240                (230)
                                                                     --------        --------           ---------
                                                                       (7,246)            (209)            (1,185)
                                                                     --------         --------           --------

NET INCOME (LOSS)                                                     (13,895)         12,803              15,726

CLASS C UNIT DISTRIBUTIONS ($1.00 PER UNIT)                            2,464              664                 664
                                                                    --------          -------             -------

NET INCOME (LOSS) ATTRIBUTABLE TO
  GENERAL PARTNER, CLASS A AND
  CLASS B LIMITED PARTNERS                                           $(16,359)       $ 12,139            $ 15,062
                                                                      =======         =======             =======

ALLOCATION OF NET INCOME (LOSS):

General partner                                                   $      886        $   2,097           $   2,569
                                                                   =========         ========            ========
Class A and Class B Limited partners                                 $(17,245)       $ 10,042            $ 12,493
                                                                      =======         =======             =======
  Per Class A Unit and Class B Unit - basic                        $    (1.86)     $     1.09          $     1.35
                                                                    =========       =========           =========
  Per Class A Unit and Class B Unit - diluted                      $    (1.86)     $     1.07          $     1.35
                                                                    =========       =========           =========
  Weighted average Class A Units and Class B
     Units outstanding                                                 9,258            9,222               9,240
                                                                     =======          =======             =======







<FN>


               The accompanying notes are an integral part of the
                       consolidated financial statements.
</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                             CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
                                                            (In thousands)


                                    General             Class A            Class B      Class C       Treasury
                                    Partner              Units              Units        Units          Units              Total

<S>                                <C>               <C>                <C>                          <C>                 <C>     
Balance, December 31, 1995         $  2,981          $ 59,614           $  1,062                     $ (6,085)           $ 57,572
Increase in Treasury Units                                                                               (894)               (894)
Syndication costs                                         (12)                                                               (12)
Issuance of Class C Units                              (5,146)                         $5,146
Distributions                        (2,243)           (5,270)                           (664)                            (8,177)
Net income                            2,569            12,301                192          664                             15,726
                                    -------           -------            -------       ------       ---------            -------

Balance, December 31, 1996            3,307            61,487              1,254        5,146          (6,979)             64,215
Syndication costs                                                                        (278)                              (278)
Distributions                        (1,824)           (5,188)                           (664)                            (7,676)
Net income                            2,097             9,885                157          664                             12,803
                                    -------            ------            -------       ------       ---------            -------

Balance, December 31, 1997            3,580            66,184              1,411        4,868          (6,979)             69,064
Issuance of Class C Units, net of
  syndication costs                                                                    16,518                             16,518
General Partner contribution            171                                                                                  171
Exercise of Unit Options                                  199                                                                199
Decrease in Treasury Units                                                                                 70                 70
Distributions                        (1,823)           (5,208)                         (2,464)                            (9,495)
Net income (loss)                       886           (16,977)              (268)       2,464                             (13,895)
                                   --------           -------           --------       ------         -------             -------

Balance, December 31, 1998         $  2,814          $ 44,198           $  1,143     $ 21,386        $ (6,909)           $ 62,632
                                    =======           =======            =======      =======         ========            =======




<FN>

               The accompanying notes are an integral part of the
                       consolidated financial statements.
</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                                 CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                            (In thousands)


                                                                               For the Year Ended December 31,
                                                                             ---------------------------------
                                                                       1998                 1997                 1996
                                                                      ------               ------               -----

OPERATING ACTIVITIES:
<S>                                                                  <C>                  <C>                  <C>     
  Net income (loss)                                                  $(13,895)            $ 12,803             $ 15,726
  Adjustments to reconcile net income (loss) to net
    cash provided by operating activities:
       Depreciation, depletion and amortization                        15,720               11,961               13,500
       Impairment of oil and gas properties                            14,000
       Depreciation charged to affiliates                                 249                  221                  265
       Asset disposals                                                   (188)
       Amortization of deferred loan costs and other assets                82                   81                  167
       Noncash interest expense                                            15                  241                  219
       Minority interest in net income                                    976                1,797                2,723
       Take-or-pay recoupment                                            (130)                (126)               (376)
       Equity in (earnings) loss of HCRC                                4,888               (1,348)             (1,768)
       Undistributed (earnings) loss of affiliates                     (1,319)                 197                (187)

  Changes in  operating  assets  and  liabilities  provided  (used)  cash net of
       noncash activity:
         Oil and gas revenues receivable                                2,861                  633              (2,638)
         Trade receivables                                              1,029                 (562)             (1,647)
         Due from affiliates                                             (362)              (2,948)               2,808
         Prepaid expenses and other current assets                       (247)                (163)                 163
         Deferred expenses and other assets                              (408)
         Accounts payable and accrued liabilities                       3,006                4,730              (2,159)
         Due to affiliates                                                                    (133)               (373)
                                                                  -----------             --------            --------
           Net cash provided by operating activities                   26,277               27,384               26,423
                                                                       ------               ------               ------

INVESTING ACTIVITIES:
  Additions to property, plant and equipment                          (28,756)              (3,233)              (3,148)
  Exploration and development costs incurred                          (12,180)             (12,983)              (9,467)
  Proceeds from sales of property, plant and equipment                    454                  133                5,294
  Distributions received from affiliate                                 1,583
  Investment in affiliates                                                (20)                 (76)                (449)
  Investment in Spraberry properties                                                                             (4,715)
  Other investing activities                                                                   (29)        
                                                                  -----------            ---------
           Net cash used in investing activities                      (38,919)             (16,188)             (12,485)
                                                                       ------               ------               ------

FINANCING ACTIVITIES:
  Payments of long-term debt                                          (18,286)              (7,285)             (11,373)
  Proceeds from the issuance of Class C Units, net
    of syndication costs                                               16,518
  Proceeds from long-term debt                                         33,000                7,000                9,000
  Distributions paid                                                   (9,495)              (7,676)              (8,177)
  Distributions paid by consolidated affiliates
    to minority interest                                               (1,446)              (1,875)              (2,429)
  Payment of contract settlement                                       (2,767)                                     (305)
  Exercise of Unit Options                                                199
  Capital contribution from the general partner                           171
  Other financing activities                                                                  (278)                 (91)
                                                                  -----------             --------            ---------
           Net cash provided by (used in) financing activities         17,894              (10,114)             (13,375)
                                                                      -------               ------               ------

NET INCREASE IN CASH AND CASH
  EQUIVALENTS                                                           5,252                1,082                  563

CASH AND CASH EQUIVALENTS:

  BEGINNING OF YEAR                                                     6,622                5,540                4,977
                                                                      -------              -------              -------

  END OF YEAR                                                        $ 11,874             $  6,622             $  5,540
                                                                      =======              =======              =======

<FN>

               The accompanying notes are an integral part of the
                       consolidated financial statements.
</FN>
</TABLE>


<PAGE>


                         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  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.
HEP's future growth will be driven by a combination  of  development of existing
projects,  exploration  for new  reserves  and select  acquisitions.  HEPGP Ltd.
became the general  partner of HEP on November 26, 1996 after its 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

As of March 24,  1999,  HEP was a party to 26  financial  contracts to hedge the
price of its oil and  natural  gas.  The  purpose  of the  hedges is to  provide
protection  against price decreases and to provide a measure of stability in the
volatile  environment of oil and natural 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.

As of March 24 1999,  HEP was a party to six  financial  contracts  to hedge the
interest payments under its Credit  Agreement.  The purpose of the hedges is the
protect  against the  variability  of the cash flows under its Credit  Agreement
which has a floating interest rate. The amounts received or paid upon settlement
of  these  transactions  are  recognized  as  interest  expense  at the time the
interest payments are due.

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.


<PAGE>


As of December 31,  1998,  HEP had a net  over-produced  position of 157,000 mcf
($298,000 valued at year-end gas prices). The general partner believes that this
imbalance can be made up with  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,  1998  have  been
decreased by 157,000 mcf in order to reflect HEP's gas balancing position.

Allocations

Partnership  costs and revenues are allocated to Class A and Class B Unitholders
and the general  partner  pursuant  to the  partnership  agreement  as set forth
below.

                                           Unitholders          General Partner

Property Costs and Revenues
  Initial acquisition costs -
    Acreage other than exploratory            100%                     0%
    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%

(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 7.5% to the
         general  partner and 92.5% to the Unitholders and share all other costs
         and revenues in a ratio of 18.75% to the general  partner and 81.25% to
         the Unitholders.

Property, Plant and Equipment

HEP follows the full cost method of accounting  whereby all costs related to the
acquisition  and  development  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.  During the second, third
and fourth  quarters  of 1998,  using oil and gas prices of $13.00 per barrel of
oil and $2.00 per mcf of gas,  $12.80 per barrel of oil and $1.90 per mcf of gas
and  $10.00  per  barrel  of oil and  $1.90  per mcf of gas,  respectively,  HEP
recorded oil and gas property impairments totaling $14,000,000.

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.


<PAGE>


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.

Long-lived  assets,  other than oil and gas  properties  which are evaluated for
impairment as described above,  are evaluated for impairment  whenever events or
changes  in  circumstances   indicate  that  the  carrying  amount  may  not  be
recoverable. To date, HEP has not recognized any impairment losses on long-lived
assets other than oil and gas properties.

Deferred Liability

The deferred  liability as of December 31, 1998 and 1997  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 12, 1999 to Unitholders of record on December 31, 1998. This amount and
the general  partner  distribution  were accrued as of year end. At December 31,
1998 and 1997, distributions payable of $2,423,000 and $2,093,000,  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 1998, 1997
and 1996.

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
effects of its  activities  accrue 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 differences between the accounting treatment of certain items for
income tax purposes and 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,  1998  and  1997,  the  income  tax  bases  of  the
Partnership's  oil  and  gas  properties  were  approximately   $94,100,000  and
$94,000,000, 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

Basic  income  (loss) per Class A and Class B Unit is computed  by dividing  net
income (loss) attributable to the Class A and Class B limited partners' interest
(net income  excluding  income (loss)  attributable  to the general  partner and
Class C Units) by the weighted average number of Class A Units and Class B Units
outstanding  during  the  periods.  Diluted  income per Class A and Class B Unit
includes the potential dilution that could occur upon exercise of the options to
acquire Class A Units  described in Note 10,  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).
Unit options have been ignored in the  computation  of diluted loss per share in
1998 because their inclusion would be anti-dilutive.


<PAGE>


The  following  table  reconciles  the number of Units  outstanding  used in the
calculation of basic and diluted income (loss) per Class A and Class B Unit.
<TABLE>
<CAPTION>

                                     Income
                                                                          (Loss)        Units        Per Unit
                                                                           (In thousands except per Unit)

For the Year Ended December 31, 1998
<S>                                                                     <C>              <C>          <C>    
   Net loss per Class A Unit and Class B Unit - basic                   $(17,245)        9,258        $(1.86)
                                                                          ------         -----         =====
     Net Loss per Class A Unit and Class B Unit - diluted               $(17,245)        9,258        $(1.86)
                                                                          ======         =====         =====

For the Year Ended December 31, 1997
   Net income per Class A Unit and Class B Unit - basic                  $ 10,042        9,222         $ 1.09
                                                                                                        =====
   Effect of Unit Options                                                                  137
                                                                       ------------     ------             
     Net Income per Class A Unit and Class B Unit - diluted              $ 10,042        9,359         $ 1.07
                                                                          =======        =====          =====

For the Year Ended December 31, 1996
   Net income per Class A Unit and Class B Unit - basic                  $ 12,493        9,240         $ 1.35
                                                                                                        =====
   Effect of Unit Options                                                                   13
                                                                       -------------   -------
     Net Income per Class A Unit and Class B Unit - diluted              $ 12,493        9,253         $ 1.35
                                                                          =======        =====          =====
</TABLE>

Treasury Units

HEP owns  approximately 46% of the outstanding  common stock of HCRC, while HCRC
owns approximately 19% of HEP's Class A Units. Consequently, HEP has an interest
in  890,242  and  899,305  of its own  Units at  December  31,  1998  and  1997,
respectively.  The 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, 1998, 1997
and 1996, purchases by the following companies exceeded 10% of the total oil and
gas revenues of the Partnership:



<PAGE>

<TABLE>
<CAPTION>

                                                      1998             1997              1996
                                                      ----             ----              ----

<S>                                                   <C>               <C>              <C>
Conoco Inc.                                           23%               20%              28%
El Paso Field Services Company                        11%               11%
Marathon Petroleum Company                                              16%              11%
</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,  1998,  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.



<PAGE>


Recently Issued Accounting Pronouncements

In June 1997,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting Standards No. 130 "Reporting  Comprehensive  Income" (SFAS
130"). SFAS 130 establishes standards for reporting and display of comprehensive
income and its components (revenues,  expenses, gains, and losses) in a full set
of general purpose financial  statements.  SFAS 130 requires that all items that
are  required to be  recognized  under  accounting  standards as  components  of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods  provided for  comparative  purposes is required.
The Partnership  adopted SFAS 130 on January 1, 1998. The  Partnership  does not
have any items of other  comprehensive  income for the years ended  December 31,
1998, 1997 and 1996. Therefore, total comprehensive income (loss) is the same as
net income (loss) for those periods.

In June 1997,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting  Standards  No.  131  "Disclosures  about  Segments  of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards
for  reporting  selected   information  about  operating  segments  and  related
disclosures about products and services,  geographic areas, and major customers.
SFAS 131 requires that an entity report  financial and  descriptive  information
about  its  operating  segments  which  are  regularly  evaluated  by the  chief
operating  decision maker in deciding how to allocate resources and in assessing
performance. HEP adopted FAS 131 in 1998.

The Partnership engages in the development,  production and sale of oil and gas,
and the  acquisition,  exploration,  development  and  operation  of oil and gas
properties in the  continental  United States.  In addition,  the  Partnership's
activities  exhibit  similar  economic  characteristics  and  involve  the  same
products, production processes, class of customers, and methods of distribution.
Management of the  Partnership  evaluates its performance as a whole rather than
by product  or  geographically.  As a result,  HEP's  operations  consist of one
reportable segment.

In June 1998,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting  Standards No. 133 "Accounting for Derivative  Instruments
and  Hedging  Activities"  ("SFAS  133").  SFAS 133  establishes  standards  for
derivative  instruments,  including certain derivative  instruments  embedded in
other  contracts  (collectively  referred  to as  derivatives)  and for  hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities  in the statement of financial  position and measure those
instruments  at fair value.  If certain  conditions are met, a derivative may be
specifically  designated  as (a) a hedge of the  exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted  transaction,  or
(c) a hedge of the foreign  currency  exposure of a net  investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated  forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation.  The Partnership is required to
adopt SFAS 133 on January 1, 2000. The Partnership has not completed the process
of evaluating the impact that will result from adopting SFAS 133.

Reclassifications

Certain  reclassifications  have been made to prior years' amounts to conform to
the classifications used in the current year.



<PAGE>


NOTE 2 - OIL AND GAS PROPERTIES

The following  table  summarizes cost  information  related to HEP's oil and gas
activities:
<TABLE>
<CAPTION>

                                                          For the Year Ended December 31,
                                                      1998             1997              1996
                                                                  (In thousands)

Property acquisition costs:
<S>                                                   <C>              <C>               <C>    
  Proved                                              $28,397          $ 1,942           $ 2,321
  Unproved                                                379            1,071               560
Development costs                                       8,087            7,607             8,218
Exploration costs                                       6,043            6,950             2,200
                                                      -------          -------           -------
      Total                                           $42,906          $17,570           $13,299
                                                       ======           ======            ======
</TABLE>

Depreciation,  depletion,  amortization and impairment expense related to proved
oil and gas  properties  per  equivalent  mcf of production  for the years ended
December 31, 1998, 1997 and 1996, was $1.57, $.73 and $.73, respectively.

At December 31, unproved properties consist of the following:
<TABLE>
<CAPTION>

                                                                      1998             1997
                                                                      ----             ----
                                                                          (In thousands)

<S>                                                                   <C>              <C>   
Texas                                                                 $1,857           $  982
North Dakota                                                             499              314
California                                                                                447
Other                                                                    338              572
                                                                      ------           ------
                                                                      $2,694           $2,315
                                                                       =====            =====
</TABLE>


NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES

As a result of the arbitration discussed in Note 13, HEP completed an $8,200,000
acquisition  of properties  located  primarily in Texas during October 1998. The
acquisition  included  interests  in 570 wells,  numerous  proven  and  unproven
drilling locations, exploration acreage and 3-D seismic data.

In July  1996,  HEP and its  affiliate,  HCRC,  acquired  interests  in 38 wells
located primarily in LaPlata County,  Colorado. An unaffiliated large East Coast
financial institution formed an entity to utilize the tax credits generated from
the wells.  The project was financed by an  affiliate  of Enron Corp.  through a
volumetric  production  payment.  During May 1998, a limited  liability  company
owned equally by HEP and HCRC purchased the volumetric  production  payment from
the affiliate of Enron Corp. HEP funded its $17,257,000 share of the acquisition
price from operating cash flow and borrowings under its Credit Agreement.

During 1997, HEP had no individually significant property acquisitions or sales.


NOTE 4 - CLASS C UNIT ISSUANCE

On February  17,  1998,  HEP closed its public  offering of 1.8 million  Class C
Units, priced at $10.00 per Unit. Proceeds to HEP, net of underwriting expenses,
were  approximately  $16,518,000.  HEP used  $14,000,000  of the net proceeds to
repay borrowings  under its Credit Agreement and applied the remaining  proceeds
toward the  repayment of HEP's  outstanding  contract  settlement  obligation at
December 31, 1997 of $2,752,000.




<PAGE>


NOTE 5 - DERIVATIVES

As part of its risk management strategy,  HEP enters into financial contracts to
hedge the price of its oil and natural  gas.  HEP does not use these  hedges for
trading  purposes,  but rather for the purpose of providing  protection  against
price  decreases  and  to  provide  a  measure  of  stability  in  the  volatile
environment  of oil and natural 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 natural
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.  As of March 24,
1999,  HEP  was  a  party  to  26  financial   contracts  with  three  different
counterparties.

The following table provides a summary of HEP's financial contracts:

                                   Oil
                         Quantity of Production
      Period                     Hedged                     Contract Floor Price
                                 (bbls)                            (per bbl)

       1996                       300,000                             $18.33
       1997                       346,000                              17.78
       1998                       175,000                              16.62
       1999                        16,000                              14.88

All of the oil  volumes  hedged in 1999 are  subject  to a  participating  hedge
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 25% of the
difference between the contract price and the posted futures price if the posted
futures price is greater than the contract  price.  All of the volumes hedged in
1999 are subject to a collar  agreement  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 $16.50
to $18.35 per barrel.



<PAGE>


                                   Gas
                         Quantity of Production
      Period                     Hedged                     Contract Floor Price
                                  (mcf)                            (per mcf)

       1996                     5,479,000                              $1.94
       1997                     5,386,000                               1.97
       1998                     7,101,000                               2.09
       1999                     6,655,000                               2.02
       2000                     5,037,000                               2.07
       2001                     3,892,000                               2.04
       2002                     2,724,000                               2.09

From 1999  forward,  between 15% and 25% of the gas volumes  hedged in each year
are subject to a collar agreement 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 price  ranges  from $2.63 per mcf to
$2.80 per mcf.



<PAGE>


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 Agreement described
in Note 7.


NOTE 6 - 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, 1998, 1997 and 1996.
<TABLE>
<CAPTION>

                                                             1998             1997              1996
                                                             ----             ----              ----
                                                                          (In thousands)

<S>                                                         <C>              <C>               <C>    
Current assets                                              $12,566          $15,145           $10,802
Noncurrent assets                                            88,601           77,226            67,666
Current liabilities                                          18,262           11,007            10,849
Noncurrent liabilities                                       53,316           32,678            24,558
Revenue                                                      32,410           32,411            34,445
Net income (loss)                                            (20,279)          5,585             8,210
</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 78,000 shares of its common stock in
odd lot repurchase offers which were completed January 26, 1996 and May 3, 1996,
respectively.  HCRC  resold  38,895 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):

Capitalized Costs Relating to Oil and Gas Activities:
<TABLE>
<CAPTION>

                                                                    As of December 31,
                                                             1998             1997                1996

<S>                                                       <C>              <C>               <C>      
Unproved properties                                       $   1,286        $   1,040         $     573
Proved properties                                           147,600          118,966           113,085
Accumulated depreciation, depletion,
  amortization and property impairment                      (100,890)         (92,511)          (89,175)
                                                             -------          -------           -------
Net property                                               $ 47,996         $ 27,495          $ 24,483
                                                            =======          =======           =======
</TABLE>

Costs Incurred in Oil and Gas Activities:
<TABLE>
<CAPTION>

                                                            For the Year Ended of December 31,
                                                             1998             1997              1996

<S>                                                       <C>               <C>               <C>    
Acquisition costs                                         $ 12,879          $ 1,303           $ 1,008
Development costs                                            2,636            2,060             3,670
Exploration costs                                            2,606            2,851               382
                                                          --------           ------           -------
     Total                                                $ 18,121          $ 6,214           $ 5,060
                                                           =======           ======            ======
</TABLE>



<PAGE>




<TABLE>
<CAPTION>

                                                                   For the Year Ended December 31,
                                                              1998             1997              1996

<S>                                                        <C>               <C>               <C>    
Oil and gas revenue                                        $ 10,372          $10,889           $11,690
Production operating expense                                  (4,272)          (3,746)           (3,790)
Depreciation, depletion, amortization
  and property impairment expense                            (13,773)          (3,336)           (3,257)
Income tax benefit (expense)                                                     (761)              23
                                                       ------------          --------        ---------
     Net income (loss) from oil and gas activities         $  (7,673)       $  3,046          $  4,666
                                                            ========         =======           =======
</TABLE>

Proved Oil and Gas Reserve Quantities:

                                                    Gas               Oil
                                                    Mcf                Bbl
                                                         (unaudited)

Balance, December 31, 1998                          32,000             1,470
                                                    ======             =====
Balance, December 31, 1997                          27,268             2,065
                                                    ======             =====
Balance, December 31, 1996                          22,786             2,680
                                                    ======             =====

Standardized Measure of Discounted Future Net Cash Flows:

                                                     (unaudited)

December 31, 1998                                      $30,134
                                                        ======
December 31, 1997                                      $31,245
                                                        ======
December 31, 1996                                      $47,701
                                                        ======


NOTE 7 - DEBT

HEP's long-term debt at December 31, 1998 and 1997 consists of the following:

                                                    1998              1997
                                                    ----              ----
                                                        (In thousands)

Credit Agreement                                   $49,700           $30,700
Note Purchase Agreement                                                4,286
                                              ------------           -------
Total                                               49,700            34,986
Less current maturities                              9,319      
                                                   -------
Long-term debt                                     $40,381           $34,986
                                                    ======            ======

During the first  quarter of 1997,  HEP and its  lenders  amended  HEP's  Second
Amended and Restated Credit  Agreement (as amended,  the "Credit  Agreement") to
extend the term date of its Credit  Agreement to May 31,  1999.  The lenders are
Morgan  Guaranty  Trust Company,  First Union  National Bank and  NationsBank of
Texas.  Under the Credit Agreement HEP has a borrowing base of $62,000,000.  HEP
had amounts  outstanding  at  December  31, 1998 of  $49,700,000.  HEP's  unused
borrowing base totaled $12,300,000 at March 24, 1999.

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%. At December 31, 1998, the applicable
interest rate was 7.125%.  Interest is payable monthly,  and quarterly principal
payments of $3,106,500 commence May 31, 1999.



<PAGE>


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

At December 31, 1998, HEP's debt maturity schedule is as follows.

                                  (In thousands)

1999                                 $  9,319
2000                                   12,425
2001                                   12,425
2002                                   12,425
2003                                    3,106
                                      -------
  Total                               $49,700

As part of its risk management strategy,  HEP enters into financial contracts to
hedge the interest rate payments  under its Credit  Agreement.  HEP does not use
the hedges for trading purposes, but rather to protect against the volatility of
the cash flows under its Credit  Agreement,  which has a floating interest rate.
The  amounts  received  or  paid  upon  settlement  of  these  transactions  are
recognized as interest expense at the time the interest payments are due.

Approximately  one  third of the debt  hedged  in 1998 was  subject  to a collar
agreement  with a floor  rate of 7.55%  and a ceiling  rate of 9.85%.  All other
contracts  are interest rate swaps with fixed rates.  As of March 24, 1999,  HEP
was a party to six contracts with three different counterparties.

The following table provides a summary of HEP's financial contracts.

                                                  Average
                           Amount of              Contract
      Period              Debt Hedged            Floor Rate

1996                      $10,000,000                6.65%
1997                       15,000,000                6.56%
1998                       15,000,000                6.84%
1999                       27,000,000                5.70%
2000                       30,000,000                5.65%
2001                       24,000,000                5.23%
2002                       25,000,000                5.23%
2003                       25,000,000                5.23%
2004                        4,000,000                5.23%





<PAGE>


NOTE 8 - 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  was recorded  equal to the present  value of this
amount  discounted  at 10.68%,  HEP's  estimated  borrowing  rate at the time of
settlement.  At December  31,  1997,  the current  contract  settlement  balance
consisted  of a payment of  $2,767,000  net of  unaccreted  discount of $15,000,
which was paid during February 1998.


NOTE 9 - 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  are equal to or greater
     than $.20 per Class A Unit.

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 the general  partner  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 10 - 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 2.75% for 1998, and 2.40% for 1997 and 1996.
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, at the conclusion
of  which  the  participants  are  each  paid a share  of an  amount  equal to a
specified  percentage (80% for 1998, 1997 and 1996) of the remaining net present
value of the  qualifying  wells,  and the award for that  year  terminates.  The
expenses  attributable to the plans were $125,000 in 1998,  $277,000 in 1997 and
$148,000 in 1996 and are included in general and  administrative  expense in the
accompanying financial statements.

On January 31, 1995, the Board of Directors of the general partner  approved the
adoption  of the  Class A Unit  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-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.

On May 5, 1998,  HEP  granted  options to  purchase  25,500  Class A Units at an
exercise  price of $6.625 per Unit,  which was equal to the fair market value of
the Units on the date of grant.  These  options  were not granted  pursuant to a
previously  existing plan but are subject to terms and  conditions  identical to
those in HEP's 1995 Class A Unit Option Plan. One-third of the options vested on
the date of grant,  and the remainder vest one-half on the first  anniversary of
the date of grant and one-half on the second anniversary of the date of grant.

During  the second  quarter  of 1998,  HEP  adopted a Class C Unit  Option  Plan
covering  120,000  Class C Units.  Options  to  purchase  all of the Units  were
granted effective May 5, 1998 at an exercise price of $10.00 per Unit, which was
equal to the fair  market  value of the Units on the date of grant.  One-half of
the options  vested on the date of grant,  and the  remainder  vest on the first
anniversary of the date of grant.


<PAGE>


A summary of options  granted to purchase Class A Units and the changes  therein
during the years ended December 31, 1998, 1997, and 1996 is presented below:



<PAGE>
<TABLE>
<CAPTION>


                                              1998                        1997                        1996
                                             ------                      ------                      -----
                                                  Weighted                    Weighted                    Weighted
                                                  Average                     Average                     Average
                                                  Exercise                    Exercise                    Exercise
                                     Units         Price         Units         Price         Units         Price

Outstanding at beginning
<S>                                 <C>           <C>            <C>            <C>          <C>            <C>  
   of year                          425,000       $  5.75        425,000        $5.75        425,000        $5.75
Granted                              25,500         6.625                                                        
 Exercised                          (34,600)         5.75                                                
                                    -------        ------    -------------   --------    -------------
 Outstanding at end of  year        415,900       $  5.80        425,000        $5.75        425,000        $5.75
                                    =======        ======        =======         ====        =======         ====

 Options exercisable at year end    398,900       $  5.80        425,000        $5.75        283,330        $5.75
                                    =======        ======        =======         ====        =======         ====
</TABLE>

A summary of options  granted  under the Class C Unit Option Plan and the 
changes  therein  during the year ended  December 31, 1998 is presented below:

                                                                   Weighted
                                                                    Average
                                                                   Exercise
                                                  Units              Price

Outstanding at beginning of year                       --         $       --
 Granted                                          120,000              10.00
                                                  -------              -----
Outstanding at end of  year                       120,000             $10.00
                                                  =======              =====

 Options exercisable at year end                   60,000             $10.00
                                                 ========              =====

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  options  granted  to  purchase  Class A and Class C Units.  Had
compensation expense for options granted been determined based on the fair value
at the grant date for the options,  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>

                                                      1998                   1997                   1996
                                                     ------                 ------                 -----

<S>                                                <C>                     <C>                    <C>        
Net income (loss):               as reported       $(13,895,000)           $12,803,000            $15,726,000
                             pro forma              (14,022,000)            12,730,000             15,544,000
Net income (loss) per Class A and B Unit - basic:
                             as reported                 $(1.86)                 $1.09                  $1.35
                             pro forma                   $(1.88)                 $1.08                  $1.33
Net income (loss) per Class A and B Unit - diluted:
                             as reported                 $(1.86)                 $1.07                  $1.35
                             pro forma                   $(1.88)                 $1.07                  $1.33

</TABLE>


<PAGE>


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>
<CAPTION>

                                            1995 Class A              1998 Class A              1998 Class C
                                            Option Plan                 Options                  Option Plan

<S>                                          <C>                         <C>                    <C>
Expected dividend yield                         6%                          8%                     11%
Expected price volatility                     28%                         27%                      29%
Risk-free interest rate                         7.6%                        6.4%                     6.4%
Expected life of options                      10 years                    10 years                 10 years
</TABLE>


NOTE 11 - 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 has  receivables  from  affiliates of HEP of $119,000 and
$588,000  at December  31,  1998 and 1997,  respectively,  which  represent  net
revenues net of operating  costs and  expenses.  The  intercompany  balances are
settled  monthly.  During 1998,  HEPGP had a payable balance to HPI which ranged
from $182,000 to $729,000.

HPI is  reimbursed  by HEP for costs and  expenses  which  include  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 1998, 1997, and 1996 were
as follows:

                                          1998           1997            1996
                                          ----           ----            ----
                                                     (In thousands)

Technical                                 $1,398           $966          $1,249
Nontechnical                                 924            896           1,110

Included in the  nontechnical  allocation  attributable to HEP's direct interest
for 1998,  1997 and 1996 is  approximately  $274,000,  $275,000,  and  $152,000,
respectively,  of  consulting  fees under a consulting  agreement  with Hallwood
Group.  Also included in the nontechnical  allocation is $317,000,  $301,000 and
$309,000 in 1998, 1997 and 1996,  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 agreement was terminated  effective  December 1996. The
amount of consulting fees allocated to the Partnership  under this agreement was
$125,000 in 1996.


NOTE 12 - STATEMENT OF CASH FLOWS

Cash paid during 1998, 1997 and 1996 for interest totaled $2,700,000, $2,775,000
and $3,492,000, respectively.




<PAGE>


NOTE 13 - ARBITRATION

In connection with the Demand for Arbitration  filed by Arcadia  Exploration and
Production Company ("Arcadia") with the American Arbitration Association against
Hallwood Energy Partners,  L.P., Hallwood  Consolidated  Resources  Corporation,
E.M.  Nominee  Partnership  Company and  Hallwood  Consolidated  Partners,  L.P.
(collectively  referred  to as  "Hallwood"),  the  arbitrators  ruled  that  the
original  agreement  entered  into  in  August  1997  to  purchase  oil  and gas
properties  should  proceed,  with a reduction  in the total  purchase  price of
approximately  $2,500,000 for title  defects.  The  arbitrators  also ruled that
Arcadia  was not  entitled to enforce its claim that  Hallwood  was  required to
purchase an additional  $8,000,000 in properties and denied  Arcadia's claim for
attorneys fees. The  arbitrators  granted  Arcadia  prejudgment  interest on the
adjusted  purchase price, but an issue exists between Hallwood and Arcadia as to
the proper calculation of the limitation which the panel placed on the amount of
prejudgment  interest.  The parties plan to ask the  arbitrators to rule on this
issue.  The Partnership has accrued  $452,000 in its financial  statements as of
December 31, 1998 in connection with this dispute.

In October 1998, HEP and its affiliate,  HCRC, closed the acquisition of oil and
gas properties from Arcadia  pursuant to the ruling which included  interests in
approximately  570 wells,  numerous  proven  and  unproven  drilling  locations,
exploration acreage, and 3-D seismic data. HEP's share of the purchase price was
$8,200,000.


NOTE 14 - LITIGATION SETTLEMENTS

Concise Oil and Gas Partnership  ("Concise"),  a wholly owned  subsidiary of the
Partnership,  was 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 portion of the
lawsuit against Concise was settled in  consideration  of the payment by Concise
of $600,000.  This amount was recorded as litigation  settlement  expense in the
second  quarter of 1998.  Concise has been  dismissed  with  prejudice  from the
lawsuit.

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 had 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% based on oil and gas prices in effect as
of December 31, 1996.



<PAGE>


NOTE 15 - COMMITMENTS

HPI currently leases office facilities under an operating lease which expires in
June 1999.  During  February  1999,  HPI entered into  another  office lease for
approximately  $600,000 per year. The new lease commences upon occupancy,  which
is expected to be in June or July 1999,  and  terminates  in seven and  one-half
years.  The lease  payments  are  included  in the  allocation  of  general  and
administrative  expenses to HEP and other affiliated entities.  HEP is guarantor
of 60% of the lease  obligation,  and HCRC is guarantor of the  remaining 40% of
the  obligation.  Rent  expense  under these  leases is allocated to HEP and its
affiliates. Remaining commitments under these leases mature as follows:

        Year Ending
       December 31,               Annual Rentals
                                  (In thousands)

           1999                      $   316
           2000                          601
           2001                          601
           2002                          601
           2003                          601
        Thereafter                     1,979
                                      $4,699

Rent expense allocated to HEP was $287,000,  $288,000 and $304,000 for the years
ended December 31, 1998, 1997 and 1996, respectively.


NOTE 16 - 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.
<TABLE>
<CAPTION>

                                                              December 31, 1998
                                                     Carrying               Estimated Fair
                                                     Amount                      Value
                                                               (In thousands) 

Assets (Liabilities):
<S>                                           <C>                            <C>     
   Oil and gas hedge contracts                $         --                   $  4,254
   Interest rate hedge contracts                        --                        (812)
   Long-term debt                                   (49,700)                   (49,700)
</TABLE>

The  estimated  fair value of the interest  rate hedge  contracts is computed by
multiplying the difference between the quoted contract termination 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 the quoted termination prices for oil and gas
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.


<PAGE>


Long-term debt is carried in the  accompanying  balance sheet at an amount which
is a reasonable estimate of its fair value.

The fair value  estimates  presented  herein are based on pertinent  information
available to  management  as of December 31, 1998.  Although  management  is not
aware of any factors that would  significantly  affect the estimated  fair value
amounts, such amounts have not been comprehensively  reevaluated for purposes of
these financial  statements since that date, and current estimates of fair value
may differ significantly from the amounts presented herein.





<PAGE>


                         HALLWOOD ENERGY PARTNERS, L.P.
                  SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
                                DECEMBER 31, 1998
                                   (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.  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  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 tax
paying  entity.  Under the  guidelines  set forth by the Securities and Exchange
Commission  (SEC),  the calculation is performed using year end prices.  The oil
and gas prices used at December 31, 1998,  1997 and 1996 were $10.00 per bbl and
$1.90 per mcf, $16.90 per bbl and $2.30 per mcf and $24.18 per bbl and $3.76 per
mcf,  respectively,  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, 1998
prices result in 4.5 million bbls of oil, and 94.9 billion cubic feet of gas and
a standardized measure of $101,000,000.  The Mays are included on a consolidated
basis, and 28,000 bbls of oil and 1.1 billion cubic feet of gas,  representing a
discounted  present  value  of  $2,100,000  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 203,000 bbls of
oil and 5 billion cubic feet of gas with a standardized measure of $7,000,000 at
December 31, 1998.

HEP's  standardized  measure  of future  net cash  flows has been  increased  by
$2,771,000  at December  31, 1998 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%.


<PAGE>
<TABLE>
<CAPTION>


                         HALLWOOD ENERGY PARTNERS, L.P.
                               RESERVE QUANTITIES
                                 (In thousands)
                                   (Unaudited)



                                                                          Gas                        Oil
                                                                          Mcf                       Bbls

Proved Reserves:
<S>                  <C> <C>                                              <C>                         <C>  
   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)
   Purchases of reserves in place                                          9,350                         17
   Production                                                            (12,786)                      (972)
                                                                         -------                   --------

   Balance, December 31, 1996                                             88,542                      7,531

   Extensions and discoveries                                              4,228                        817
   Revisions of previous estimates                                        11,578                     (1,930)
   Sales of reserves in place                                               (140)                        (9)
   Purchases of reserves in place                                            619                        128
   Production                                                            (11,774)                      (770)
                                                                         -------                   --------

   Balance, December 31, 1997                                             93,053                      5,767

   Extensions and discoveries                                              1,542                        415
   Revisions of previous estimates                                        (9,369)                    (1,385)
   Sales of reserves in place                                               (244)                       (35)
   Purchases of reserves in place                                         23,994                        512
   Production                                                            (14,037)                      (787)
                                                                         -------                   --------

   Balance, December 31, 1998                                             94,939                      4,487
                                                                         =======                    =======

Proved Developed Reserves:
   Balance, December 31, 1996                                             85,848                      7,056
                                                                         =======                    =======
   Balance, December 31, 1997                                             89,816                      5,181
                                                                         =======                    =======
   Balance, December 31, 1998                                             90,915                      3,577
                                                                         =======                    =======
</TABLE>



<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                       STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
                                                            (In thousands)
                                                              (Unaudited)


                                                                            December 31,
                                                       1998                     1997                     1996
                                                       ----                     ----                     ----

<S>                                                 <C>                      <C>                     <C>       
Future cash flows                                   $  245,000               $  293,000              $  509,000
Future production and development costs               (102,000)                (115,000)               (175,000)
                                                       -------                 --------                --------
Future net cash flows before discount                  143,000                  178,000                 334,000
10% discount to present value                          (42,000)                 (49,000)               (128,000)
                                                     ---------                ---------                --------
Standardized measure of discounted
   future net cash flows                            $  101,000               $  129,000              $  206,000
                                                     =========                =========               =========
</TABLE>




<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L.P.
                                CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
                                                            (In thousands)
                                                              (Unaudited)



                                                                               For the Year Ended December 31,
                                                                               -------------------------------
                                                                      1998                   1997                  1996
                                                                      ----                   ----                  ----

Standardized measure of discounted future net
<S>                                                                  <C>                   <C>                    <C>     
   cash flows at beginning of year                                   $129,000              $206,000               $124,000

Sales of oil and gas produced, net of production costs                (26,932)             (30,209)               (35,915)

Net changes in prices and production costs                            (21,211)             (78,965)                 75,085

Extensions and discoveries, net of future production
  and development costs                                                 3,546                 9,592                  7,144

Changes in estimated future development costs                          (9,738)             (10,012)                (6,515)

Development costs incurred                                              8,087                 7,607                  8,218

Revisions of previous quantity estimates                              (15,547)                  (8)                 20,032

Purchases of reserves in place                                         23,802                 1,457                 14,721

Sales of reserves in place                                               (399)                (204)                (9,742)

Accretion of discount                                                  12,936                20,600                 12,400

Changes in production rates and other                                  (2,544)                3,142                (3,428)
                                                                     --------              --------             ---------

Standardized measure of discounted future net
  cash flows at end of year                                          $101,000              $129,000               $206,000
                                                                      =======               =======                =======
</TABLE>



<PAGE>


ITEM 9 -     DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
             DISCLOSURES

None.


                                    PART III


ITEM 10 -    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The registrant is a limited  partnership  managed by the general partner and has
no officers or directors.  The general partner is HEPGP Ltd., a Colorado limited
partnership.  The  general  partner of HEPGP Ltd.  is  Hallwood  G.P.,  Inc.,  a
Delaware corporation, which is a wholly owned subsidiary of Hallwood Group.

The principal  duties and powers of the general partner are arranging  financing
for HEP,  seeking out,  negotiating  and acquiring  for HEP suitable  leases and
other prospects,  managing  properties owned by HEP,  generally  dealing for HEP
with third  parties and attending to the general  administration  of HEP and its
relations with the limited partners.

Hallwood  Petroleum,  Inc.  ("HPI") performs duties related to the management of
HEP,  including  the  operations  of  various  properties  in which  HEP owns an
interest.

Directors, Officers and Key Employees

Neither the Partnership nor its general partner has any employees. Following are
brief biographies of the directors,  officers and key employees of Hallwood G.P.
and HPI.

Anthony J. Gumbiner, 54, has served as a director and Chief Executive Officer of
Hallwood G.P. since March 1997. He was Chairman of the Board of Hallwood  Energy
Corporation  ("HEC") from May 1984 until HEC's  merger into The  Hallwood  Group
Incorporated ("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 Hallwood  Consolidated  Resources
Corporation  ("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,  55, 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.


<PAGE>


Russell P. Meduna,  44, 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,  46, 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.

Thomas J. Jung, 50, has served as Vice President and Chief Financial  Officer of
Hallwood G.P.,  HCRC and HPI since May 1998. From January 1997 until April 1998,
he was a Senior  Financial  Associate  with Trinity  Petroleum  Management,  and
during that period,  he also  provided  consulting  services to other  companies
involved in the  development,  financing,  management  and  monetization  of tax
credits  for  alternative  energy  projects.  From  1994 to 1996,  he was  Chief
Executive  Officer of FAR Gas Acquisitions  Corp. From 1986 to 1994, he was Vice
President and Chief Financial Officer of NICOR Exploration & Production  Company
and Reliance Pipeline Company.

Betty J. Dieter,  51, 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 26 years experience in accounting and operations, 19 of which are in the
oil and gas industry. Ms. Dieter is a Certified Public Accountant.

George  Brinkworth,  57, 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 34 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,  48, 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 24 years oil and gas engineering experience.

Brian M. Troup,  51, 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 of Hallwood  Group.  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,  56, 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,  69, 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.


<PAGE>


Nathan C.  Collins,  64, has served as a director of Hallwood  G.P.  since March
1997.  He was a  director  of HEC from March 1995  until  November  1996.  Since
February  1999, he has been a consultant  in banking  products  development  for
Nordstrom,  Inc. He is also a director of First  State Bank of  Flagstaff.  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.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the  Securities  Exchange Act of 1934 requires the officers and
directors of Hallwood  G.P.,  Inc., and persons who own more than ten percent of
HEP's  Units,  to file reports of  ownership  and changes in ownership  with the
Securities  and Exchange  Commission.  Officers,  directors and greater than ten
percent  owners are required by SEC regulation to furnish HEP with copies of all
Section 16(a) forms they file.

Based  solely on its  review  of the  copies of such  forms  received  by it, or
written  representations  from  certain  reporting  persons  that no forms  were
required for those persons,  HEP believes  that,  during the year ended December
31, 1998,  all officers and  directors of Hallwood  G.P.,  Inc. and greater than
ten-percent  beneficial  owners  complied with applicable  filing  requirements,
except that Mr. Thomas Jung filed his initial statement of beneficial  ownership
late. Mr. Jung did not beneficially own any Units of HEP.


ITEM 11 - EXECUTIVE COMPENSATION

General

Neither the Partnership  nor its 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 1998 the Partnership  reimbursed HPI for approximately
$2,322,000 of expenses,  of which $548,000 was attributable to compensation paid
to executive officers of Hallwood G.P.

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,  1998)  for  services  to the  Partnership,  its
subsidiaries and its General Partner for the years ended December 31, 1998, 1997
and 1996.


<PAGE>

<TABLE>
<CAPTION>

                                                      Summary Compensation Table


                                                                                      Long Term
                                                      Annual Compensation           Compensation
                                                                                     Securities
                                                                                     Underlying           LTIP           All Other
Name & Principal Position               Year       Salary             Bonus         Options/SARs        Payouts        Compensation
-------------------------               ----       ------             -----         ------------        -------        ------------
                                                                                         (#)                                (1)

<S>                                     <C>    <C>               <C>                     <C>       <C>                <C>       
Anthony J. Gumbiner (2)                 1998   $          0      $          0            (5)       $         (6)      $        0
   Chief Executive                      1997              0                 0            (3)                 (6)               0
   Officer                              1996        250,000                 0             0                  (6)               0

William L. Guzzetti                     1998        204,811           162,800            (5)             30,523            4,800
   President and Chief                  1997        204,294           143,870            (3)             42,854            4,750
   Operating Officer                    1996        204,294           131,500             0              33,170            5,699

    Russell P. Meduna                   1998        163,664            99,000            (5)             30,523            4,800
   Executive Vice                       1997        163,664           111,520            (3)             42,854            4,750
   President                            1996        163,664           101,900             0              33,170            4,500

 Thomas J. Jung                         1998         82,850            60,000          (4)(5)                 0            1,922
   Vice President and
   Chief Financial Officer

Cathleen M. Osborn                      1998        119,614            74,500            (5)             21,458            4,800
   Vice President and                   1997        105,685           100,000            (3)             30,124            4,750
   General Counsel                      1996        105,685            62,400             0              23,092            4,500
<FN>

(1)      Employer contribution to 401(k) and a service award of $1,199 paid to Mr. Guzzetti in 1996.
</FN>
<FN>

(2)      For 1996,  Mr.  Gumbiner  had a  Compensation  Agreement  with HPI.
         $250,000 was paid  under this  agreement  in 1996. The Compensation
         Agreement  terminated  effective  December 1996. In addition to 
         compensation  listed in the table, HPI had a consulting agreement  with
         Hallwood  Group for 1996,  pursuant to which  Hallwood  Group  received
         an annual consulting fee of $300,000 from  affiliates of HPI.  During
         1997 and 1998,  the  Partnership  participated  in a new financial  
         consulting agreement between HPI and Hallwood Group,  pursuant to which
         Hallwood Group received a fee of $550,000  from  the  Partnership  and
         its  affiliates.  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.
</FN>
<FN>

(3)      Consists of the following HCRC options granted in 1997, which have been
         adjusted for a 3-for-1 split effective in 1997.



                                        Securities Underlying
            Name                           Options/SARs (#)

Anthony J. Gumbiner                             47,700
William L. Guzzetti                             23,850
Russell P. Meduna                               22,260
Cathleen M. Osborn                               9,540



</FN>
<FN>

(4)          Consists of the following options granted in 1998.

                                                   Securities Underlying
       Name                    Company                Options/SARs (#)

Thomas J. Jung                  HEP                         25,500
                                HCRC                         9,540
</FN>
<FN>

(5)          Consists of the following HEP Class C Unit options granted in 1998.

                                      Securities Underlying
            Name                         Options/SARs (#)

Anthony J. Gumbiner                            34,588
William L. Guzzetti                            16,588
Russell P. Meduna                              14,118
Cathleen M. Osborn                             10,024
Thomas J. Jung                                 10,024
</FN>
<FN>

(6)      Payments were made to HSC Financial,  with which Mr.  Gumbiner is 
         associated,  in the amount of $67,977 for 1998,  $54,750 for 1997 and
         $9,943 for 1996.
</FN>
</TABLE>

Option Grants and Exercises in Last Fiscal Year

The  following  table sets forth the  options to  purchase  Class C Units of HEP
granted to executive  officers during 1998. No options to purchase Class C Units
granted to executive officers were exercised in 1998.
<TABLE>
<CAPTION>

                                              Option/SAR Grants in Last Fiscal Year
                                                                                                     Potential Realized Value at
                                                                                                     Assumed Annual Rates of
                                                                                                     Unit Price Appreciation
                                                           Individual Grants                         for Option Term (2)
                                      Number of        % of Total
                                      Securities      Options/SARs
                                      Underlying         Granted      Exercise or                      5%              10% 
                                     Options/SARs     Employees in     Base Price    Expiration      $16.29          $25.94 
              Name                   Granted (1)       Fiscal Year      ($/Unit)        Date       Unit Price      Unit Price 
              ----                   -----------      -------------    ----------    ----------    ----------      ----------

<S>                                      <C>                <C>         <C>           <C>           <C>             <C>     
Anthony J Gumbiner                       34,588             24          $10.00        05/05/08      $217,522        $551,244
William L. Guzzetti                      16,588             11           10.00        05/05/08       104,321         264,370
Russell P. Meduna                        14,118             10           10.00        05/05/08        88,787         225,005
Cathleen M. Osborn                       10,024              7           10.00        05/05/08        63,040         159,757
Thomas J. Jung                           10,024              7           10.00        05/05/08        63,040         159,757
<FN>

(1)          Options have a ten-year term and vest cumulatively 1/2 on the grant
             date and 1/2 on first  anniversary  of the grant date.  All Options
             vest immediately in the event of certain changes in control of HEP.
</FN>


<PAGE>


<FN>

(2)      Securities and Exchange Commission Rules require  calculation of 
         potential  realizable value assuming that the market price of the Class
         C Units  appreciates in value at 5% and 10% annualized  rates.  At a 5%
         annualized  rate of  appreciation, the Class C Unit price  would be 
         $16.29 at the end of ten  years.  At a 10%  annualized  rate of  
         appreciation,  the Class C Unit price would be $25.94 at the end of ten
         years.  No gain to an  executive  officer is  possible  without an
         appreciation  in Class C Unit value,  which will  benefit  all  holders
         of Class C Units.  The actual  value an executive  officer may receive
         depends on market prices for the Class C Units,  and there can be no
         assurance  that the amounts reflected will actually be realized.
</FN>
</TABLE>

The  following  table sets forth the  options to  purchase  Class A Units of HEP
granted  to an  executive  officer  during  1998.  None of  these  options  were
exercised in 1998.
<TABLE>
<CAPTION>

                                              Option/SAR Grants in Last Fiscal Year
                                                                                       Potential Realized Value at
                                                                                       Assumed Annual Rates of
                                                                                       Unit Price Appreciation
                                             Individual Grants                         for Option Term (2)
                        Number of        % of Total
                        Securities      Options/SARs
                        Underlying         Granted      Exercise or                      5%              10% 
                       Options/SARs     Employees in     Base Price    Expiration      $10.79          $17.18 
       Name            Granted (1)       Fiscal Year     ($/Share)        Date       Unit Price      Unit Price 
       ----            -----------      -------------   -----------    ----------    ----------      ----------

<S>                        <C>                <C>         <C>           <C>           <C>             <C>     
Thomas J. Jung             25,500             18          $6.625        05/05/08      $106,244        $269,243
<FN>

(1)  Options have a ten-year term and vest  cumulatively over three years at the
     rate of 1/3 on the grant date and the first two  anniversaries of the grant
     date.  All  Options  vest  immediately  in the event of certain  changes in
     control of HEP.
</FN>
<FN>

(2)  Securities and Exchange  Commission Rules require  calculation of potential
     realizable  value  assuming  that the  market  price  of the  Class A Units
     appreciates  in value at 5% and 10%  annualized  rates.  At a 5% annualized
     rate of appreciation,  the Class A Unit price would be $10.79 at the end of
     ten years. At a 10% annualized rate of appreciation, the Class A Unit price
     would be $17.18 at the end of ten years. No gain to an executive officer is
     possible without an appreciation in Class A Unit value,  which will benefit
     all holders of Class A Units.  The actual  value an  executive  officer may
     receive depends on market prices for the Class A Units, and there can be no
     assurance that the amounts reflected will actually be realized.
</FN>
</TABLE>



<PAGE>


The following  table shows  exercises of options to purchase Units and shares of
common  stock during 1998 and the value of  unexercised  options on December 31,
1998.
<TABLE>
<CAPTION>

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

                                                                           Number of Securities
                                                                                Underlying           Value of Unexercised
                                                                                Unexercised               In-the-Money
            Name                                                               Options/SARs               Options/SARs
                                                                              at FY - End (#)            at FY -End ($)
                                       Units Acquired        Value             Exercisable/               Exercisable/
                                      on Exercise (#)    Realized ($)      Unexercisable (1)(3)       Unexercisable (2)(4)
                                      ---------------    ------------      --------------------       --------------------

<S>                          <C>         <C>              <C>              <C>                           <C> 
Anthony J. Gumbiner          HEP                                           144,794 / 17,294                     0 / 0
                             HCRC          4,000            33,820          75,500 / 15,900               189,221 / 0
William L. Guzzetti          HEP                                           72,044 /   8,294                     0 / 0
                             HCRC                                          39,750 /   7,950               103,271 / 0
Russell P. Meduna            HEP                                           66,559 /   7,059                     0 / 0
                             HCRC          2,500            21,700         34,600 /   7,420                85,561 / 0
Cathleen M. Osborn           HEP           9,100            11,497         21,412 /   5,012                     0 / 0
                             HCRC          5,000            42,900         10,900 /   3,180                19,658 / 0
Thomas J. Jung               HEP                                            13,512 / 22,012                     0 / 0
                             HCRC                                            6,360 / 12,720                     0 / 0

<FN>

(1)      The HEP Class A Unit 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.  The HEP Class C Unit
         Options  have a ten year term and vest 1/2 on the date of grant and 1/2
         on  the  first   anniversary  of  the  grant  date.  All  options  vest
         immediately  in  the  event  of  certain  changes  in  control  of  the
         Partnership.
</FN>
<FN>

(2)      The exercise price of the HEP Class A Unit Options  granted in 1995 and
         in 1998 is  $5.75  and  $6.625  per  Class  A Unit,  respectively.  The
         exercise  price  of the HEP  Class C Unit  Options  granted  in 1998 is
         $10.00  per Class C Unit.  The  closing  price of the Class A Units was
         $3.625 on December 31, 1998 and the closing  price of the Class C Units
         was $6.625 on December 31, 1998.
</FN>
<FN>

(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.
</FN>
<FN>

(4)      The  exercise  price of the HCRC  options  granted in 1995 is $6.67 per
         share,  and the exercise  price of the HCRC options  granted in 1997 is
         $20.33 per share.  The closing  price of the common stock was $11.00 on
         December 31, 1998. The exercise  prices have been adjusted to reflect a
         3-for-1 stock split effective in 1997.
</FN>
</TABLE>



<PAGE>


Long-Term Incentive Plan

The  following  table  describes  performance  units  awarded  to the  executive
officers of Hallwood G.P. for 1998 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.
<TABLE>
<CAPTION>

                                       Long-Term Incentive Plan Awards in Last Fiscal Year

                                                  Performance or            Estimated Future
                                  Number of        Other Period          Payouts under Non-Stock
         Name                       Units          Unit Payout            Price-Based Plans (1)
         ----                    -----------     ---------------        -----------------------

<S>                               <C>                 <C>                   <C>         
Anthony J. Gumbiner(2)                 --                --                 $         --
William L. Guzzetti                0.0727              2003                       18,176
Russell P. Meduna                  0.0727              2003                       18,176
Cathleen M. Osborn                 0.0545              2003                       13,625

<FN>

(1)      The 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 percent  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.
</FN>
<FN>

(2)      In addition, an award of .3818 units, with an estimated  future  payout
         of $95,453,  was made to HSC  Financial,  with which Mr. Gumbiner is 
         associated.  The payout period ends in 2003.
</FN>
</TABLE>

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 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 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
afterward,  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.



<PAGE>


The  awards for the 1998 Plan Year were made in January  1998.  No other  awards
were  made in 1998.  For the 1998  Plan  Year,  the  Compensation  Committee  of
Hallwood G.P.  determined  that the total Plan Cash Flow would be equal to 2.75%
of the cash flow of the domestic wells completed, recompleted or enhanced during
the 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 1998 Plan Year
would be purchased in the sixth year at 80% of the  remaining  net present value
of the  wells  completed  in the Plan  Year.  The  Compensation  Committee  also
determined that the total award would be allocated among key employees primarily
on the basis of salary and, to a lesser extent,  on the basis of contribution to
HEP's drilling activity.

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 1998, 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  1998.  Mr.
Gumbiner  is  Chief  Executive  Officer  and a  director,  and Mr.  Guzzetti  is
President and a director,  of Hallwood Realty. During 1998, 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 1997, 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  $274,000  and $275,000 was paid in 1998 and
1997,  respectively by the Partnership  pursuant to this arrangement.  For 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.

The Partnership reimburses Hallwood Group for expenses incurred on behalf of the
Partnership.  In 1998, 1997 and 1996 the Partnership  reimbursed  Hallwood Group
for approximately $317,000, $301,000 and $309,000 of expenses, respectively.


<PAGE>


ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
             MANAGEMENT

The  following  table  shows  information,  as of  March  24,  1999,  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 and directors as a group.
<TABLE>
<CAPTION>

                                                                                 Amount
                                                            Title of          Beneficially
                         Name                            Class of Units           Owned        Percent of Class

<S>                                                         <C>                <C>                     <C>
The Hallwood Group Incorporated (1)                          Class A           657,260(5)              6.5
                                                             Class B           143,773               100.0
                                                             Class C            43,816                 1.8

Hallwood Consolidated Resources Corporation (2)              Class A         1,948,189                19.5
                                                             Class C           129,877                 5.3

Heartland Advisors, Inc. (3)                                 Class A           803,760(6)              8.0

Estate of William Baxter Lee, III (4)                        Class A           715,000(7)              7.1
                                                             Class C            40,033(8)              1.6

Anthony J. Gumbiner                                          Class A           127,500(9)              1.3
                                                             Class C            17,294(10)               *

William L. Guzzetti                                          Class A            63,850(9)                *
                                                             Class C             8,300(10)               *

Russell P. Meduna                                            Class A            59,500(9)                *
                                                             Class C             7,059(10)               *

Cathleen M. Osborn                                           Class A            16,400(9)                *
                                                             Class C             5,112(10)               *

Thomas J. Jung                                               Class A             8,500(9)                *
                                                             Class C             5,012(10)               *

Brian M. Troup                                               Class A            85,000(9)                *
                                                             Class C            11,294(10)               *

Hans-Peter Holinger                                          Class A                 -                   -
                                                             Class C                 -                   -

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

Nathan C. Collins                                            Class A                 -                   -
                                                             Class C                 -                   -

Bill M. Van Meter                                            Class A                 -                   -
                                                             Class C                 -                   -

All directors and executive officers of                      Class A           361,150(11)             3.7
Hallwood G.P. as a group (9 persons)                         Class C            54,097(12)               *
----------------------
<FN>

*        Less than 1%
</FN>
<FN>

(1) The address of Hallwood Group is 3710 Rawlins Street, Suite 1500,
    Dallas, Texas 75219.
</FN>
<FN>

(2) The  address of Hallwood  Consolidated  Resources  is 4582 S. Ulster  Street
    Parkway,  Suite 1700,  Denver,  Colorado  80237.
</FN>
<FN>

(3) The  address of  Heartland Advisors,  Inc. is 790 North  Milwaukee  Street,
    Milwaukee,  WI 53202.
</FN>
<FN>
(4) The address of the Estate of William Baxter Lee, III, is c/o Glankler Brown,
    PLLC, 1700 One Commerce Sq.,  Memphis,  TN 38103.
</FN>
<FN>
(5) Includes  143,773 Class B Units (100% of the Class B Units) that are 
    convertible into Class A Units one-for-one.
</FN>
<FN>
(6) According to the  Amendment No. 4 to Schedule 13G filed January 26, 1999 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.
</FN>
<FN>
(7) According to Schedule 13G dated February 23, 1999.
</FN>
<FN>
(8) According to Schedule 13G dated February 23, 1999.
</FN>
<FN>
(9) The  following  numbers of Class A Units  issuable  upon the  exercise of 
    currently  exercisable  options are included in the amounts shown: 
    Mr. Gumbiner,  127,500;  Mr. Troup,  85,000;  Mr.  Guzzetti,  63,750;  
    Mr. Meduna,  59,500;  Ms. Osborn, 16,400;  Mr. Jung 8,500.
</FN>
<FN>
(10)The  following  numbers of Class C Units  issuable  upon the  exercise of  
    currently  exercisable  options are included in the amounts  shown:
    Mr.  Gumbiner, 17,294;  Mr. Troup,  11,294;  Mr.  Guzzetti,  8,294;  
    Mr.  Meduna,  7,059;  Ms. Osborn, 5,012;  Mr. Jung, 5,012.
</FN>
<FN>
(11)Consists of 500 Class A Units and currently exercisable options to purchase
    360,650 Class A Units.
</FN>
<FN>
(12)Consists of 132 Class C Units and currently exercisable options to purchase
    53,965 Class C Units.
</FN>
</TABLE>

See  Item 8 -  Financial  Statements  and  Supplementary  Data  (Note  10 to the
Financial Statements) for a description of HEP's Unit Option Plans.


ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

See  Item 8 -  Financial  statements  and  Supplementary  Data  (Note  11 to the
Financial Statements).



                                     PART IV


ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)      Financial Statements and Financial Statement Schedules.  (See Index at
         Item 8).
(b)      Reports on Form 8-K.
         HEP filed no current reports on Form 8-K during the last quarter of the
         period covered by this report.
(c)      Exhibits.

   (1)   4.1      - Third Amended and Restated Agreement of Limited Partnership 
                    of Hallwood Energy Partners, L.P.
   (4)   4.2      - Unit  Purchase  Rights  Agreement  dated as of February 6, 
                    1995  between HEP and The First  National  Bank of Boston.
   (7)   4.3      - First  Amendment  to the Third  Amended and  Restated  
                    Agreement of Limited  Partnership  of Hallwood  Energy
                    Partners, L. P.
   (8)   4.4      - Amendment to the Third Amended and Restated  Agreement of 
                    Limited  Partnership of Hallwood  Energy  Partners, L.P.
   (12)  4.5      - Correction  to the First  Amendment  to the Third  Amended 
                    and  Restated  Limited  Partnership  Agreement  of Hallwood
                    Energy Partners, L.P.
   (3)   10.1     - Third Amended and Restated Agreement of Limited Partnership
                    of HEP Operating Partners, L.P.
   (5)   10.3     - Second Amended and Restated Credit Agreement dated March 31,
                    1995
   (2)   10.4     - Amended and Restated Note Purchase Agreement dated May 7, 
                    1990.  (Exhibit 10.2)
   (3)   10.5     - Amended and Restated Agreement of Limited Partnership of 
                    EDP Operating, Ltd.
  *(5)   10.9     - Domestic Incentive Plan between the Partnership and Hallwood
                    Petroleum, Inc. dated January 14, 1993
  *(6)   10.10    - 1995 Unit Option Plan
  *(5)   10.11    - 1995 Unit Option Plan Loan Program
   (8)   10.12    - Amendment to the Third Amended and Restated Agreement of 
                    Limited Partnership of HEP Operating Partners, L.P.
   (8)   10.13    - Second  Amendment  to the Second  Amended and  Restated  
                    Agreement of Limited  Partnership  of HEP  Operating 
                    Partners, L.P.
  *(9)   10.14    - Financial Consulting Agreement dated as of December 31, 1996
   (10)  10.15    - Third Amended and Restated Credit Agreement dated as of 
                    May 31, 1997
   (11)  10.16    - Amendment No. 1 to Third Amended and Restated Credit
                    Agreement dated as of October 31, 1997
  *(13)  10.17    - 1998 Class C Unit Option Plan dated May 5, 1998
  *(13)  10.18    - 1998 Class C Unit Option Loan Program dated May 5, 1998
  *(13)  10.19    - Class A Unit Option letter to Thomas Jung dated May 5, 1998
   (13)  10.20    - Extension of Management Agreement between Hallwood 
                    Petroleum, Inc. and HEP dated May 5, 1998.
   (14)  10.21    - Merger and Asset  Contribution  Agreement  By and Among
                    Hallwood  Energy  Corporation,  and HEC  Acquisition
                    Corp.,  Hallwood  Energy  Partners,   L.P.  and  HCRC
                    Acquisition  Corp.,  Hallwood  Consolidated  Resources
                    Corporation and HEPGP Ltd. dated as of December 15, 1998.
    (7)  21       - Subsidiaries of Registrant
         23.1     - Consent of Deloitte & Touche LLP
         23.2     - Consent of Deloitte & Touche LLP
         27       - Financial Data Schedule
   ------------

(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 exhibit  shown in  parentheses  
         filed with current  report on Form 8-K dated May 9, 1990 of
         Hallwood Energy Partners, L.P.
(3)      Incorporated  by reference to the same exhibit number filed with the 
         Registrant's  Annual Report on Form 10-K for fiscal year ended
         December 31, 1990.
(4)      Incorporated  by reference to Exhibit 1 filed with the  Registrant's  
         Form 8-A for Limited  Partner Unit Purchase Rights filed with the SEC 
         on February 8, 1995.
(5)      Incorporated  by reference to the same exhibit number filed with
         Registrant's  Quarterly  Report on Form 10-Q for the quarter ended
         March 31, 1995.
(6)      Incorporated  by reference to the same exhibit number filed with the
         Registrant's  Annual Report on Form 10-K for fiscal year ended December
         31, 1994.
(7)      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.
(8)      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.
(9)      Incorporated  by reference  to the same  exhibit  number  filed with
         the  Registrant's  Quarterly  Report on Form 10-Q for the quarter ended
         March 31, 1997.
(10)     Incorporated  by reference  to the same  exhibit  number  filed with 
         the  Registrant's  Quarterly  Report on Form 10-Q for the quarter ended
         June 30, 1997.
(11)     Incorporated  by reference  to the same  exhibit  number  filed with
         the  Registrant's  Quarterly  Report on Form 10-Q for the
         quarter ended September 30, 1997.
(12)     Incorporated by reference to same exhibit number filed with the 
         Registrant's  Quarterly Report on Form 10-Q ended March 31, 1998.
(13)     Incorporated  by reference to same exhibit  number filed with the 
         Registrant's  Quarterly  Report on Form 10-Q ended June 30, 1998.
(14)     Incorporated by reference to Schedule 14A of HEP dated 
         December 30,1998.


         *Designates management contracts or compensatory plans or arrangements.


<PAGE>


SIGNATURES

Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934,  the  registrant  has duly  caused  this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

                                                  HALLWOOD ENERGY PARTNERS, L.P.
                                                  BY:  HEPGP LTD
                                                       General Partner

                                                  BY:  HALLWOOD G.P., INC.
                                                       General Partner


Date:  March 24, 1999                             By:  /s/William L. Guzzetti 
     --------------------------------------       ----------------------------
                               William L. Guzzetti
                             President and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following  persons on behalf of the  registrant and
in the capacities and on the dates indicated.

  Signature                                           Capacity           Date



/s/Anthony J. Gumbiner      Chairman of the Board and             March 24, 1999
Anthony J. Gumbiner         Director (Chief Executive Officer)


/s/Brian M. Troup            Director                             March 24, 1999
Brian M. Troup


/s/Hans-Peter Holinger       Director                             March 24, 1999
Hans-Peter Holinger


/s/Rex A. Sebastian          Director                             March 24, 1999
Rex A. Sebastian


/s/Nathan C. Collins         Director                             March 24, 1999
Nathan C. Collins


/s/Thomas J. Jung           Principal Accounting Officer          March 24, 1999
Thomas J. Jung



<PAGE>


                                INDEX TO EXHIBITS


                                                                            Page

Exhibit 23.1 - Consent of Deloitte & Touche LLP                               75

Exhibit 23.2 - Consent of Deloitte & Touche LLP                               76