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, 1997

   [ ] 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:

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

           Securities Registered Pursuant to Section 12(g) of the Act:
                                      None

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. [x]


The  aggregate  market  value  of  the  Class  A  and  Class  C  Units  held  by
nonaffiliates  of the  registrant  as of  February  27,  1998 was  approximately
$58,218,000.

Number of Units outstanding as of February 27, 1998
   Class A                                                             9,986,254
   Class B                                                              143,773
   Class C                                                            2,464,063

                                  Page 1 of 64

<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 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 February 27, 1998, HPI had 123 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 entered into
financial contracts for hedging the price of 23% of its estimated oil production
for 1998 and 2% for 1999.

The majority of HEP's  natural gas  production is sold on the spot market and is
transported in intrastate and interstate  pipelines.  HEP entered into financial
contracts  for  hedging  the price of  between 4% and 42% of its  estimated  gas
production for 1998 through 2001.

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.

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  purchasers  in the  areas in which  HEP sells its
production.  However,  for the years ended  December  31,  1997,  1996 and 1995,
purchases  by the  following  companies  exceeded  10% of the  total oil and gas
revenues of the Partnership:
<TABLE>
<CAPTION>

                                                     1997              1996             1995
                                                     ----              ----             ----

<S>                                                   <C>               <C>              <C>
Conoco Inc.                                           20%               28%              30%
Marathon Petroleum Company                            16%               11%              14%
El Paso Field Services Company                        11%   
</TABLE>

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 involve the extraction,
production and transportation of materials which, under certain conditions,  can
be  hazardous or can cause  environmental  pollution  problems.  In light of the
current  interest in environmental  matters,  the general partner cannot predict
what effect possible future public or private action may have on the business of
HEP. 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, 1997,  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

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

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


ITEM  2 -  PROPERTIES

Exploration and Development Projects

In 1997, HEP incurred  $16,216,000 in direct property  additions and exploration
and development costs. The costs were comprised of approximately $12,983,000 for
domestic exploration and development  expenditures and approximately  $3,233,000
for property  acquisitions.  In 1997,  HEP  participated  in  approximately  102
drilling or recompletion  projects, the highlights of which are discussed below.
HEP's 1997 capital program led to the replacement,  including revisions to prior
year reserves,  of 63% of 1997  production.  Sales of reserves in place in 1997,
which  were  approximately  1% of  1997  production,  were  excluded  from  this
calculation.  Approximately $2,130,000 of the 1997 capital expenditures were for
land and seismic data  anticipated  to yield  prospects for 1998 and  subsequent
years.

Property Sales

During 1997, HEP received approximately $133,000 for the sale of 50 nonstrategic
properties located in eight states.

Capital Projects

Greater Permian Region

HEP has expended  approximately  $6,400,000 of its capital budget in the Greater
Permian Region located in Texas and Southeast New Mexico. During 1997, HEP spent
approximately $4,740,000 drilling 29 development wells and 26 exploration wells,
and acquiring  undeveloped  acreage and geological and geophysical  data. Of the
wells drilled,  39 (71%) were successful.  A discussion of several of the larger
projects within the Region follows.

HEP spent approximately $1,085,000 successfully recompleting two wells, drilling
one successful development well, and drilling two unsuccessful exploration wells
in the Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico.

HEP spent approximately  $220,000 to drill six exploration and three development
wells  in the  nonoperated  Merkle  Project  in the  Jones,  Taylor,  and  Nolan
Counties, Texas. Five wells were successful.

Based on the success in the nonoperated  Merkle area, HEP acquired 74 additional
square miles of proprietary 3-D seismic data adjacent to the non-operated  area.
In 1997, HEP incurred  approximately  $650,000 acquiring acreage and drilling 10
exploration wells, seven of which were successful.  HEP purchased an interest in
proprietary 3-D seismic data and selected acreage within an 85 square mile area,
referred to as the Griffin Project,  for  approximately  $495,000.  In 1997, HEP
drilled one successful  and one  unsuccessful  exploratory  well in the area for
approximately  $370,000.  HEP is currently  participating in the drilling of one
exploration well and incurred approximately $110,000 through December 31, 1997.

HEP spent  approximately  $1,030,000  drilling  two  exploration  wells and nine
development  wells in the Spraberry  area of West Texas.  Of the wells  drilled,
eight (73%) are successful.  In July 1997, HEP acquired additional  interests in
34 of its existing wells in the area for approximately $510,000.

In 1997, HEP continued to devote capital  resources to the East Keystone area in
Winkler County, Texas. HEP spent approximately  $400,000 drilling 14 development
wells with a success rate of 100%.

Rocky Mountain Region

HEP  expended  approximately  $3,040,000  of its  capital  budget  in the  Rocky
Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico
and  Wyoming.  During  1997,  HEP  drilled or  participated  in the  drilling or
recompletion of 17 wells,  seven of which were successful.  A description of the
Region's major projects follows.

In the San Juan Basin in LaPlata  County,  Colorado and Rio Arriba  County,  New
Mexico,  HEP has an interest in 34 wells owned by a special purpose entity owned
by a large east coast  financial  institution.  During  1997,  seven  successful
recompletions on these wells were performed and one successful  exploration well
was  drilled.  This work and other  activity in the San Juan region have yielded
significant  upward  revisions to HEP's  estimated  reserve  base.  HEP incurred
approximately  $235,000 on four other recompletion  attempts in San Juan County,
New Mexico, two of which were successful.  In addition, HEP purchased additional
interests in existing wells in the area for $70,000.

In the Lone Tree area of Montana,  HEP drilled two  exploration  wells and three
development wells for a cost of approximately  $920,000.  Two of the development
wells and one of the exploration wells were successful.

HEP owns an interest in the Hudson  Ranch  project,  which is a  multi-objective
exploration  project  generated from 120 miles of 2-D proprietary  seismic data.
HEP's 1997 costs for the project are approximately  $340,000. A 3-D seismic data
acquisition  program is underway,  and  exploratory  drilling is  anticipated to
begin in 1998.

HEP also  participated in the drilling of an 11,500 feet exploration well in the
Beach  Field  of  North  Dakota.   HEP  incurred   approximately   $215,000  for
participation in this successful well.

Gulf Coast Region

HEP expended  approximately  $3,610,000 of its capital  budget in the Gulf Coast
Region in  Louisiana  and South and East  Texas.  During  1997,  HEP  drilled or
participated  in the  drilling  of six  development  wells,  five of which  were
successful,  and two unsuccessful  exploration wells, for a total cost to HEP of
approximately $2,160,000.
Major projects within the Region follow.

HEP incurred  approximately  $770,000  developing  two  Jeffress  Field wells in
Hidalgo County,  Texas. Both wells were successful.  Two successful  development
wells in the Mercy Field in San  Jacinto  County,  Texas cost HEP  approximately
$450,000. HEP also spent approximately $855,000 on two unsuccessful  exploration
attempts and one unsuccessful development well. Repairs and successful workovers
on wells in the Scott Field cost HEP approximately $800,000.

HEP also incurred  approximately  $195,000 on miscellaneous  projects within the
Region for land and geological data.

Other

The remaining  $3,166,000 of HEP's 1997 capital  budget was devoted to all other
areas.  In 1997, HEP incurred  $645,000 for land,  geological  data and drilling
costs for 15 development wells and six exploration  wells. Of the wells drilled,
17 (81%) were successful. A description of the major projects follow.

HEP is participating in an exploration prospect in Carter County, Oklahoma. This
project is a 19,000 feet deep  multi-formation  structural test and is currently
in the completion  phase.  The drilling and land costs to HEP are  approximately
$355,000.

In 1997, HEP entered into an agreement  with another  operator to participate in
an 8,500 feet deep Spiro/Foster test well in LeFlore County,  Oklahoma. The well
was a success and cost HEP approximately $265,000.

HEP also purchased  additional interests in eight existing Kansas properties for
approximately $110,000.

Projects  begun in the  fourth  quarter  of 1996  have  cost  HEP  approximately
$995,000 in 1997.  These costs are  primarily  for work in the Gulf Coast Region
and in the  Greater  Permian  Region.  Miscellaneous  land  and  geological  and
geophysical data acquired in 1997 cost HEP approximately $690,000.

In September  1997,  HEP and an  unaffiliated  partner were awarded a deep-water
exploration  block offshore of northern  Peru. Its partner is proceeding  with a
1,200 mile seismic  program to further  evaluate the project.  HEP's partner,  a
major  oil  company,  is the  operator,  and HEP has a  carried  interest  until
drilling begins.

For 1998,  HEP's capital  budget,  which will be paid from cash  generated  from
operations, cash on hand and borrowings under HEP's line of credit, has been set
at $25,000,000.  HEP's plans include  projects in Texas,  New Mexico,  Colorado,
North Dakota, and Montana.

Partnership Reserves, Production and Discussion by Significant Areas and Fields

The following  table  presents the December 31, 1997 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                 28,564             692             $   561            $  39,289     $  39,850
Gulf Coast Region                      23,710             604                 647               51,788        52,435
Rocky Mountain Region                  38,430           4,012                 269               29,607        29,876
Other                                   2,349             459                 105                6,734         6,839
                                        -----             ---                 ---                -----         -----
                                       93,053           5,767              $1,582             $127,418      $129,000
                                       ======           =====               =====              =======       =======
</TABLE>

The total present  value of future net cash flows is  calculated  using year end
average oil and gas prices.  At December 31, 1997,  oil and gas prices  averaged
$16.90 per bbl of oil and $2.30 per mcf of gas. If average oil and gas prices as
of February  27, 1998 of $15.70 per bbl of oil and $2.10 per mcf of gas had been
used,  the total  present  value of future  net cash  flows  would have been 12%
lower.


<PAGE>


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, 1997               Year Ended December 31, 1996
                                         ----------------------------               ----------------------------
                                       Natural Gas          Bbls of Oil          Natural Gas          Bbls of Oil
                                          (mcf)               (bbls)                (mcf)               (bbls)
                                                                       (In thousands)

<S>                                        <C>                  <C>                  <C>                   <C>
Greater Permian Region                     2,803                423                  2,792                 512
Gulf Coast Region                          4,859                184                  6,015                 239
Rocky Mountain Region                      3,562                100                  3,394                 137
Other                                        550                 63                    585                  84
                                             ---                 --                    ---                 ---
                                          11,774                770                 12,786                 972
                                          ======                ===                 ======                 ===
</TABLE>

The following  table presents the  Partnership's  extensions and  discoveries by
significant regions.

<TABLE>
<CAPTION>
                                               For the Year Ended 1997                        For the Year Ended 1996
                                               -----------------------                        -----------------------
                                       Mcf of Gas           Bbls of Oil          Mcf of Gas           Bbls of Oil
                                       ----------           -----------          ----------           -----------
                                                                      (In thousands)

<S>                                       <C>                    <C>                   <C>                 <C>
Greater Permian Region                    1,423                  232                   704                 422
Gulf Coast Region                         1,527                   75                   176                  15
Rocky Mountain Region                     1,153                  490                   670                  28
Other                                       125                   20                   133                  19
                                          ------                 ----                  ---        -         --
                                          4,228                  817                 1,683                 484
                                          =====                 =====                =====                 ===
</TABLE>

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

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 512
productive  oil and gas wells (443 of which are operated),  38 operated  shut-in
oil and gas wells and 15 (14 operated)  salt water  disposal  wells or injection
wells.  During  1997,  HEP  drilled or  recompleted  55 wells,  39 of which were
successful.  The following is a description of the significant  areas within the
Greater Permian Region.

Carlsbad/Catclaw  Area.  HEP's  interests  in the  Carlsbad/Catclaw  Area  as of
December 31, 1997 consisted of 61 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 40 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.   During  1997,  HEP
participated in the drilling or recompletion of five wells,  three of which were
successful. HEP has future plans for six additional projects in this area.

East Keystone Area.  HEP's interest in the East Keystone Area as of December 31,
1997  consisted  of 54  producing  wells,  38 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 1997, HEP had
14 development  projects,  all which were successful.  HEP's future  development
plans include a total of five projects for this area.


<PAGE>


Merkle Area.  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.  HEP's  focus in this area is  exploration  of the
Canyon,  Strawn and Ellenberger  formations at depths of 3,500 to 6,500 feet. In
1997, HEP  participated  in the drilling or  recompletion of six exploration and
three development wells, five of which were successful.

Based on its success in the nonoperated  Merkle Area, HEP acquired 74 additional
miles of proprietary 3-D seismic data adjacent to the nonoperated area. In 1997,
HEP drilled ten exploration  wells in the area,  seven of which were successful.
All of these  wells are  operated  by HPI.  Future  plans for this area  include
drilling 22 exploration wells, with possible  additional  exploratory  locations
contingent upon continued success.

Spraberry  Area.  HEP's interests in the Spraberry Area consist of 345 producing
wells,  11 salt  water  disposal  wells and 29 shut-in  wells in Dawson,  Upton,
Reagan and Irion Counties,  Texas. HPI operates 385 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 1997, HEP drilled or recompleted 11 wells,  eight of
which were successful.  Future plans for this area include 20 development  wells
and workovers and additional projects contingent upon future evaluation.

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 10  producing  gas wells,  one  shut-in gas well and six salt water
disposal  wells  located  in  Lafayette  Parish,  Louisiana.  The wells  produce
principally  from  the Bol Mex  formations  at  13,500  to  14,500  feet and are
operated  by HPI.  The two  most  significant  wells  in the  area  are the A.L.
Boudreaux #1 and the G.S.  Boudreaux  Estate #1.  During 1997,  HEP drilled five
successful  development  wells,  one  unsuccessful  development  well,  and  two
unsuccessful exploration wells.

Rocky Mountain Region

HEP has  significant  interests in the Rocky  Mountain  Region,  which  includes
producing  properties  in  Colorado,  Montana,  North Dakota and  Northwest  New
Mexico.  HEP has interests in 203 producing oil and gas wells,  172 of which are
operated by HPI, 44 shut-in  wells,  35 of which are  operated by HPI,  and five
salt water disposal  wells.  The following is a description  of the  significant
areas within the Rocky Mountain Region.

San Juan Basin.  HEP's  interest in the San Juan Basin  consists of 82 producing
gas wells located in San Juan County,  New Mexico and LaPlata County,  Colorado.
HPI operates 51 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.  During 1997,
HEP drilled or recompleted four wells, two of which were successful.

In 1996, HEP  participated  in the  acquisition of interests in 38 producing gas
wells in LaPlata  County,  Colorado  and Rio Arriba  County,  New Mexico  from a
subsidiary of Public Service Company of Colorado.  Thirty-four of the wells were
assigned  to a special  purpose  entity  owned by a large East  Coast  financial
institution.   The  wells   produce  from  the  Fruitland   Coal   formation  at
approximately 3,200 feet. In connection with the acquisition,  HEP monetized the
Section 29 tax credits  generated by the wells. The project was financed through
a third  party  lender  using a  production  payment  structure.  In  1997,  HEP
successfully  recompleted  seven  of  the  wells,  and  drilled  one  successful
exploration well. Future plans for this area include a total of eight projects.

Toole County Area. HEP's interests in the Toole County Area consist of 67 wells,
58 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.  During 1997,  HEP drilled one
successful  well.  HEP has plans for future  development  wells and workovers in
this area.

Lone Tree,  Richland  County  Area.  HEP's  interest in the Lone Tree,  Richland
County area consists of 13 producing  wells operated by HPI in Richland  County,
Montana.  The oil wells produce  principally from the Mission Canyon,  Interlake
and Red River  formations at depths of 9,000 feet to 12,000 feet.  In 1997,  HEP
drilled two  exploration  and three  development  wells.  Two of the development
wells and one of the exploration wells were successful.

Average Sales Prices and Production Costs

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

<TABLE>
<CAPTION>

                                                               1997              1996               1995
                                                               ------            ------             ----

Oil and condensate -                                          
<S>                                                              <C>             <C>               <C>   
   includes the effects of hedging (per bbl)                     $19.08          $20.10            $17.36
Natural gas -                                                          
   includes the effects of hedging (per mcf)                       2.31            2.24              1.82
Production costs (per equivalent bbl of oil)                       4.05            3.71              3.57
</TABLE>
                                                                
Productive Oil and Gas Wells

The following  table  summarizes the productive oil and gas wells as of December
31, 1997 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                                       650               245
   Gas                                       320               121
                                             ---               ---
      Total                                  970               366
                                             ===               ===
Oil and Gas Acreage

The following table sets forth the developed and undeveloped  leasehold  acreage
held  directly by HEP as of December 31, 1997.  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.



<PAGE>



                                             Gross              Net

Developed acreage                            99,250            48,200
Undeveloped acreage                         284,328            77,089
                                            -------    -       ------
      Total                                 383,578           125,289
                                            =======           =======

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


<PAGE>


Drilling Activity

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

<TABLE>
<CAPTION>

                                                                           Year Ended December 31,
                                       1997                                      1996                           1995
                           -           -----             -                       -----  -                       ----
                                  Gross             Net            Gross                 Net           Gross                Net
Development Wells:
<S>                                  <C>            <C>               <C>                <C>              <C>              <C> 
   Productive                        23             4.5               29                 6.6              66               28.0
   Dry                                5              .8                4                  .9               2                 .5
                                     --              --               --                  --              --                 --
      Total                          28             5.3               33                 7.5              68               28.5
                                     ==             ===               ==                 ===              ==               ====

Exploratory Wells:
   Productive                        14             2.2                2                  .2               5                 .6
   Dry                               22             5.4                4                  .6               1                 .9
                                     --             ---               --                  --              --                ----
      Total                          36             7.6                6                  .8               6                1.5
                                     ==             ===               ==                  ==              ==                ===
</TABLE>
                                    
Office Space

HPI leases  office space in Denver,  Colorado  containing  approximately  41,000
square  feet,  for  approximately  $600,000  per year.  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
Hallwood  Consolidated  Resources  Corporation  ("HCRC")  is  guarantor  of  the
remaining 40% of the obligation.


ITEM 3  -  LEGAL PROCEEDINGS

See Notes 12 and 13 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 1997.



                                     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 February 27, 1998,  9,986,254  Class A Units were
outstanding,  held by  approximately  19,673  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 1996                        $   5 1/4         $   3 3/4                   $.13
Second quarter 1996                           6 3/4             4 5/8                     .13
Third quarter 1996                            7 3/8             5 7/8                     .13
Fourth quarter 1996                           9                 6 1/4                     .13
                                                                                          ---
                                                                                         $.52
                                                                                          ===

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
                                                                                        =====
</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 February 27,
1998,  2,464,063 Class C Units were  outstanding,  held by  approximately  1,321
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

First quarter 1996                        $  7 7/8         $   6 1/2                 $   .25
Second quarter 1996                          8 1/2             7 3/8                     .25
Third quarter 1996                           9 5/8             8                         .25
Fourth quarter 1996                          9 7/8             8 3/4                     .25
                                            ------           -------                     ---
                                                                                       $1.00
                                                                                       =====

<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
                                                                                        ====
</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 Years Ended December 31,
                                            1997            1996               1995              1994             1993
                                      -     -----       -   -----        -     -----       -     -----       -    ----
                                                                 (In thousands except per Unit)

Summary of Operations
   Oil and gas revenues and               
<S>                                          <C>            <C>               <C>               <C>              <C>     
      pipeline operations                    $ 44,707       $ 50,644          $ 43,454          $ 43,899         $ 44,106
   Litigation settlement                                                                                           11,466
   Total revenue                               45,103         51,066            43,780            44,482           49,613
   Production operating                              
      expense                                  11,060         11,511            11,298            12,177           11,200
   Depreciation, depletion and                       
      amortization                             11,961         13,500            15,827            18,168           17,076
   Impairment                                                                   10,943             7,345
   General and administrative                        
      expense                                   5,333          4,540             5,580             5,630            6,812
   Net income (loss)                           12,803         15,726            (9,031)          (10,093)          13,064
   Basic net income (loss) per                       
     Class A and Class B Unit*                   1.09           1.35             (1.07)            (1.20)            1.14
   Diluted net income (loss) per                                                 
     Class A and Class B Unit *                  1.07           1.35             (1.07)            (1.20)            1.14
   Distributions per Class A                         
     and Class B Unit                             .52            .52               .80               .80              .80
                                             
Balance Sheet
   Working capital (deficit)              $     (973)      $  (1,355)        $  (4,363)        $  (9,390)       $   7,020
   Property, plant and                                    
      equipment, net                          94,331          88,549            94,926           107,414          122,133
   Total assets                              131,603         122,792           125,152           136,281          171,624
   Long-term debt                             34,986          29,461            37,557            25,898           38,010
   Long-term contract                                     
      settlement obligation                                    2,512             2,397             2,666            3,673
   Deferred liability                          1,180           1,533             1,718             1,931            1,504
   Minority interest in                                   
      affiliates                               3,258           3,336             3,042             2,923            3,346
   Partners' capital                          69,064          64,215            57,572            78,803           98,576
<FN>
                                               
*Per Unit  amounts  have been  restated to reflect the  adoption of Statement of
  Financial  Accounting  Standards  No. 128 "Earnings per share" ("SFAS 128") in
  December 1997.
</FN>
</TABLE>




<PAGE>


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

Liquidity and Capital Resources

Cash Flow

HEP generated $27,384,000 of cash flow from operating activities during 1997.

   The other primary cash inflows were:

         $7,000,000 in proceeds from long-term debt;

         $133,000 in proceeds from the sale of property.

   Cash was used primarily for:

        Distributions to partners of $7,676,000;

        Additions to property, exploration and development costs of $16,216,000;

        Payments of long-term debt of $7,285,000.

When combined with miscellaneous other cash activity during the year, the result
was an increase in HEP's cash and cash equivalents of $1,082,00, from $5,540,000
at December 31, 1996 to $6,622,000 at December 31, 1997.

Property Purchases, Sales and Capital Budget

In 1997, HEP incurred  $16,216,000 in direct property  additions and exploration
and development costs. The costs were comprised of approximately $12,983,000 for
domestic exploration and development  expenditures and approximately  $3,233,000
for property  acquisitions.  HEP's 1997 capital program led to the  replacement,
including  revisions to prior year  reserves,  of 63% of 1997  production  using
year-end pricing.

HEP's significant direct exploration and development expenditures in the Greater
Permian  Region  in 1997  included  approximately  $1,085,000  for  successfully
recompleting  or  drilling  three  development   wells,  and  for  drilling  two
unsuccessful  exploration wells in the Carlsbad/Catclaw  Draw areas in northeast
New  Mexico;  approximately  $650,000  for  acquiring  acreage  and  drilling 10
exploration wells,  seven of which were successful,  in the operated Merkle area
in West Texas;  approximately  $1,030,000 for drilling two exploration wells and
nine development wells in the Spraberry area of West Texas,  eight of which were
successful;  approximately  $510,000 for the purchase of additional interests in
the Spraberry area; and approximately $400,000 for drilling 14 development wells
in the Keystone area in West Texas, all of which were successful.

In the Lone Tree area of the Rocky Mountain Region,  HEP drilled two exploration
wells and three development wells for a cost of approximately  $920,000.  Two of
the development wells and one of the exploration  wells were successful.  In the
Gulf Coast Region, HEP incurred  approximately  $770,000 drilling two successful
Jeffress Field development wells. HEP also spent  approximately  $855,000 on two
unsuccessful exploration attempts and one unsuccessful development well. Repairs
and  successful  workovers  on wells in the Scott  Field cost HEP  approximately
$800,000.

Projects  begun in the  fourth  quarter  of 1996  have  cost  HEP  approximately
$995,000 in 1997.  These costs are  primarily  for work in the Gulf Coast Region
and in the Greater Permian Region.

For 1998,  HEP's capital  budget,  which will be paid from cash  generated  from
operations,  cash on hand and  borrowings,  has been set at  $25,000,000.  HEP's
plans  include  projects  in Texas,  New Mexico,  Colorado,  North  Dakota,  and
Montana.

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.

Distributions

During 1997, 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 Board of Directors of HEP's General Partner is considering the  distribution
level for  future  quarters,  taking  into  account  oil and gas  prices and the
capital needs of HEP.

Unit Option Plan

On January 31, 1995, the board of directors of the general partner  approved the
adoption  of the  1995  Unit  Option  Plan to be used  for  the  motivation  and
retention of directors,  employees and consultants  performing services for 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, 1997, 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  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 line of credit to May 31,  1999.  Under the  Credit
Agreement and an Amended and Restated Note Purchase  Agreement  ("Note  Purchase
Agreement")  (collectively  referred to as the "Credit  Facilities"),  HEP has a
borrowing base of $46,000,000.  HEP has amounts outstanding at December 31, 1997
of $30,700,000 under the Credit Agreement and $4,286,000 under the Note Purchase
Agreement.  Subsequent  to December  31,  1997,  HEP repaid  $14,000,000  of its
borrowings  under the  Credit  Agreement  and repaid  its  outstanding  contract
settlement  obligation of  $2,732,000;  therefore,  HEP's unused  borrowing base
totaled $25,014,000 at February 27, 1998.


<PAGE>


Borrowings under the Note Purchase  Agreement bear interest at an annual rate of
11.85%,  which is payable  quarterly.  Annual  principal  payments of $4,286,000
began April 30,  1992,  and the debt is required to be paid in full on April 30,
1998.  HEP  intends to fund the  payment  due in April 1998  through  additional
borrowings under the Credit  Agreement;  thus, no portion of HEP's Note Purchase
Agreement is classified as current as of December 31, 1997.

Borrowings  against  the  Credit  Agreement  bear  interest  at the lower of the
Certificate  of Deposit rate plus from 1.375% to 1.875%,  prime plus 1/2% or the
Euro-Dollar  rate plus from 1.25% to 1.75%.  At December 31, 1997 the applicable
interest rate was 7.5%. Interest is payable monthly,  and 16 quarterly principal
payments of $2,187,000,  as adjusted for the anticipated  borrowings to fund the
Note Purchase Agreement payment due in 1998, commence May 31, 1999.

The borrowing base for the Credit Facilities is redetermined  semiannually.  The
Credit  Facilities are secured by a first lien on approximately  80% in value of
HEP's oil and gas properties.  Additionally, aggregate distributions paid by HEP
in any 12 month  period are limited to 50% of cash flow from  operations  before
working capital changes 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.

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

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,  1997,  HEP had a net  over-produced  position of 162,000 mcf
($374,000  valued at average annual 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
162,000 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" ("SAFS
130"). SAFS 130 established 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  is  required  to  adopt  SFAS  130 on  January  1,  1998.  The
Partnership  has not completed  the process of  evaluating  the impact that will
result from  adopting  SFAS 130 or the manner that will be used to disclose  the
required information in its financial statements.

Cautionary Statement Regarding Forward-Looking Statements

In the  interest  of  providing  the  Partnership's  Unitholders  and  potential
investors 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 to 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 other  things,  volatility  of oil and gas prices,  competition,
risks inherent in the Partnership's  oil and gas operations,  the inexact nature
of  interpretation  of  seismic  and  other  geological  and  geophysical  data,
imprecision  of reserve  estimates,  the  Partnership's  ability to replace  and
expand oil and gas reserves,  and such other risks and  uncertainties  described
from time to time in the  Partnership's  periodic  reports and filings  with the
Securities  and Exchange  Commission.  Accordingly,  Unitholders  and  potential
investors are cautioned that certain events or circumstances  could cause actual
results to differ materially from those projected.

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,  and  government  regulations  and tax laws.
Prices  for  both  oil and gas have  fluctuated  from  1995  through  1997.  The
following  table presents the 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>  
1997                $19.35                   $19.08                      $2.54                    $2.31
1996                 20.85                    20.10                       2.38                     2.24
1995                 16.98                    17.36                       1.58                     1.82
</TABLE>

HEP has entered into numerous 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 following table provides a summary of HEP's financial contracts:
<TABLE>
<CAPTION>


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

<S>                     <C>                                      <C>                     <C>   
                        1998                                     23%                     $16.62
                        1999                                      2%                     $15.38
</TABLE>



<PAGE>


Between  9% and 100% of the oil  volumes  hedged in each year 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.
Between 59% and 100% of the 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 prices range from $17.00 to $18.85 per barrel.



<PAGE>

<TABLE>
<CAPTION>

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

<S>                          <C>                                       <C>                     <C>  
                             1998                                      42%                     $2.04
                             1999                                      24%                     $1.87
                             2000                                      14%                     $2.01
                             2001                                       4%                     $1.55
</TABLE>




Between  0% and 38% 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 is $2.93 per mcf.

During the first quarter  through  February 27, 1998,  the weighted  average oil
price (for  barrels  not hedged) was  approximately  $15.70 per barrel,  and the
weighted  average  price of natural gas (for mcf not  hedged) was  approximately
$2.10 per mcf.

Inflation

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

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 1997, HEP owned  interests which ranged from 57.5% to
68.2% of the Mays;  in 1996 HEP's  ownership  in the Mays  ranged  from 54.5% to
68.5%,  and in 1995  HEP's  ownership  in the Mays  ranged  from 54.5% to 68.3%.


<PAGE>

<TABLE>
<CAPTION>

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

                                            For the Year Ended December 31, 1997          For the Year Ended December 31, 1996
                                            ------------------------------------          ------------------------------------
                                           Direct                                           Direct
                                           Owned             Mays         Total             Owned       Mays             Total

                                           
<S>                                          <C>              <C>           <C>               <C>        <C>               <C>
Oil production (bbl)                            691              79            770               862        110               972
Gas production (mcf)                         10,426           1,348         11,774            11,003      1,783            12,786
                                                                                  
Average oil price                            $18.94          $20.27         $19.08            $19.92     $21.52            $20.10
Average gas price                           $  2.23         $  2.91        $  2.31           $  2.11    $  3.05           $  2.24
                                                                                  
Oil revenue                                 $13,089          $1,601        $14,690           $17,167     $2,367           $19,534
Gas revenue                                  23,302           3,918         27,220            23,178      5,440            28,618
Pipeline and other revenue                    2,797                          2,797             2,492                        2,492
Interest income                                 324              72            396               356         66               422
                                                ---            ----            ---            ------       -----           ------
      Total revenue                          39,512           5,591         45,103            43,193       7,873            51,066
                                             ------           ------        ------           -------      ------            ------

Production operating                          10,498            562          11,060           10,782         729            11,511
Facilities operating                             641                            641              726                           726
General and administrative                     4,953            380           5,333            4,131         409             4,540
Depreciation, depletion, and amortization     10,630          1,331          11,961           11,729       1,771            13,500
Interest                                       3,096                          3,096            3,878                         3,878
Equity in income of HCRC                      (1,348)                        (1,348)          (1,768)                       (1,768)
Minority interest                                             1,797           1,797                        2,723             2,723
Litigation settlement (income) expense          (234)            (6)           (240)             223           7               230
                                                ----           ----            ----             ----      ------             ------
   Total expense                              28,236          4,064          32,300           29,701       5,639            35,340
                                              ------          -----          ------           ------       -----            ------
      Net income                             $11,276         $1,527         $12,803          $13,492      $2,234           $15,726
                                              ======          =====          ======           ======       =====            ======
                                                      
</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                  TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
                                            (In thousands except price)
                                       For the Year Ended December 31, 1995

                                                            Direct
                                                            Owned             Mays             Total

<S>                                                          <C>               <C>              <C>
Oil production (bbl)                                             895               98               993
Gas production (mcf)                                          11,497            1,538            13,035

Average oil price                                             $17.32           $17.74            $17.36
Average gas price                                            $  1.81          $  1.92           $  1.82

Oil revenue                                                 $ 15,501          $ 1,739          $ 17,240
Gas revenue                                                   20,822            2,948            23,770
Pipeline and other revenue                                     2,444                              2,444
Interest                                                         263               63               326
                                                                 ---               --               ---
      Total revenue                                           39,030            4,750            43,780
                                                              ------            -----            ------

Production operating                                          10,658              640            11,298
Facilities operating                                             794                                794
General and administrative                                     5,131              449             5,580
Depreciation, depletion, and amortization                     14,058            1,769            15,827
Impairment of oil and gas properties                          10,943                             10,943
Interest                                                       4,245                              4,245
Equity in loss of HCRC                                         2,273                              2,273
Minority interest                                                               1,465             1,465
Litigation settlement expense                                    337               49               386
                                                                 ---               --               ---
   Total expense                                              48,439            4,372            52,811
                                                              ------            -----            ------
      Net income (loss)                                    $  (9,409)        $    378          $ (9,031)
                                                            ========          =======           =======
</TABLE>



<PAGE>


1997 Compared to 1996

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.

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.

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.

Pipeline, Facilities and Other

Pipeline,  facilities 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  $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

Facilities  operating  expense  represents  operating  expenses  associated with
various smaller  gathering  systems  operated by HEP. The decrease in facilities
operating expense of $85,000 is primarily due to decreased  maintenance activity
during 1997 as compared with 1996.



<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  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.

Equity in Earnings of HCRC

Equity in earnings of HCRC  represents  HEP's share of its equity  investment in
HCRC. HEP's equity in HCRC's earnings 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 Partnership  resulting  primarily
from decreased production from their properties.

Litigation Settlement Income (Expense)

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.

1996 Compared to 1995

Oil Revenue

Oil revenue increased $2,294,000 during 1996 as compared with 1995. The increase
is  comprised  of a 16% increase in the average oil price from $17.36 per barrel
in 1995 to  $20.10  per  barrel  in 1996,  partially  offset  by a  decrease  in
production,  from  993,000  barrels  in 1995 to  972,000  barrels  in 1996.  The
decrease  in  production  is due to  property  sales  and to  normal  production
declines.

The effect of HEP's hedging transactions was to decrease HEP's average oil price
from $20.85 per barrel to $20.10 per barrel, resulting in a $729,000 decrease in
oil revenue for 1996.



<PAGE>


Gas Revenue

Gas revenue  increased  by  $4,848,000  during 1996 as compared  with 1995.  The
increase is  comprised of a 23% increase in the average gas price from $1.82 per
mcf in 1995 to $2.24  per mcf in 1996,  partially  offset by a  decrease  in gas
production  from  13,035,000  mcf during 1995 to 12,786,000 mcf during 1996. The
decrease in production is due to decreases in allowable production limits and to
normal  production  declines,  partially  offset by  increased  production  from
exploratory and  developmental  drilling  projects in Montana,  Wyoming and West
Texas.

The effect of HEP's hedging transactions was to decrease HEP's average gas price
from $2.38 per mcf to $2.24 per mcf,  representing a $1,790,000  decrease in gas
revenues for 1996.

Interest Income

The  increase in interest  income of $96,000  during 1996 as compared  with 1995
resulted from a higher average cash balance during 1996 as compared with 1995.

Production Operating Expense

Production  operating  expense  increased  $213,000 during 1996 as compared with
1995,  primarily  as a  result  of  increased  production  taxes  due to the 17%
increase in oil and gas revenue during 1996 discussed above.

Facilities Operating Expense

The decrease in  facilities  operating  expense of $68,000 is  primarily  due to
decreased maintenance activity during 1996.

General and Administrative Expense

General and administrative expenses decreased $1,040,000 during 1996 as compared
with 1995  primarily  due to a decrease in  performance  based  compensation,  a
decrease in salaries  expense and  employee  benefits  expense due to  personnel
reductions  during 1995 and lower legal expense in 1996 due to the settlement of
a significant lawsuit during 1995.

Depreciation, Depletion and Amortization Expense

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

Interest Expense

Interest  expense  decreased by $367,000  during 1996 as compared with 1995. The
decrease  is due to a lower  average  outstanding  debt  balance  during 1996 as
compared to 1995.

Equity in Earnings (Loss) of HCRC

HEP's equity in HCRC's earnings  increased by $4,041,000 during 1996 as compared
to 1995.  The  increase  is  primarily  the  result  of a 6%  increase  in HEP's
ownership of HCRC resulting from HEP's purchase of 38,895 shares of common stock
of HCRC during the second  quarter of 1996.  Also  contributing  to the increase
were higher oil and gas prices for HCRC during 1996 and the inclusion in 1995 of
impairment  expense  resulting  from the  write-off of HCRC's  investment  in an
Indonesian project and other property impairments.

Litigation Settlement Expense

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



<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                                                                                  25

Consolidated Balance Sheets at December 31, 1997 and 1996                                                  26-27

Consolidated Statements of Operations for the years
  ended December 31, 1997, 1996 and 1995                                                                      28

Consolidated Statements of Partners' Capital for the
  years ended December 31, 1997, 1996 and 1995                                                                29

Consolidated Statements of Cash Flows for the years
  ended December 31, 1997, 1996 and 1995                                                                      30

Notes to Consolidated Financial Statements                                                                 31-47

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION - (UNAUDITED)                                                 48-51

</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, 1997 and 1996 and for each of the three years
in the period  ended  December  31,  1997,  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, 1997 and 1996, and the results of its operations and its cash flows
for each of the three years in the period ended  December 31, 1997 in conformity
with generally accepted accounting principles.



DELOITTE & TOUCHE LLP

Denver, Colorado
February 27, 1998



<PAGE>

<TABLE>
<CAPTION>

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

                                                                                                         December 31,

                                                                                                     1997             1996
                                                                                                    -----             ----

                CURRENT ASSETS
<S>                                                                                              <C>             <C>       
                   Cash and cash equivalents                                                     $    6,622      $    5,540
                   Accounts receivable:                                                                      
                      Oil and gas revenues                                                            8,772           9,405
                      Trade                                                                           4,609           4,507
                   Due from affiliates                                                                  588  
                   Prepaid expenses and other current assets                                          1,551             928
                                                                                                    -------           -----
                        Total                                                                        22,142          20,380
                                                                                                    -------          ------ 
                PROPERTY, PLANT AND EQUIPMENT, at cost                                                       
                   Oil and gas properties (full cost method):                                                
                      Proved mineral interests                                                      624,621         607,875
                      Unproved mineral interests - domestic                                           2,315           1,244
                   Furniture, fixtures and other                                                      3,513           3,366
                                                                                                    -------           -----
                        Total                                                                       630,449         612,485
                   Less accumulated depreciation, depletion,                                                 
                      amortization and property impairment                                          (536,118)      (523,936)
                                                                                                     -------        -------
                        Total                                                                        94,331          88,549
                                                                                                             
                OTHER ASSETS                                                                                 
                   Investment in common stock of HCRC                                                15,048          13,700
                   Deferred expenses and other assets                                                    82             163
                                                                                                     ------          ------
                        Total                                                                        15,130          13,863
                                                                                                     ------          ------
                                                                                                             
                TOTAL ASSETS                                                                       $131,603        $122,792
                                                                                                   ========        ========















<FN>

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


<PAGE>
<TABLE>
<CAPTION>


                                          HALLWOOD ENERGY PARTNERS, L.P.
                                            CONSOLIDATED BALANCE SHEETS
                                                  (In thousands)
                                                                                                   December 31,

                                                                                            1997              1996
                                                                                      -     -----       -     ----

                CURRENT LIABILITIES
<S>                                                                                      <C>                 <C>      
                   Accounts payable and accrued liabilities                              $  19,915           $  15,185
                   Due to affiliates                                                                               159
                   Net working capital deficit of affiliate                                    448                 581
                   Current portion of contract settlement                                    2,752 
                   Current portion of long-term debt                                                             5,810
                                                                                            -------             ------
                        Total                                                               23,115              21,735
                                                                                            -------             ------
                                                                                                   
                NONCURRENT LIABILITIES                                                             
                   Long-term debt                                                           34,986              29,461
                   Contract settlement                                                                           2,512
                   Deferred liability                                                        1,180               1,533
                                                                                            -------             ------
                        Total                                                               36,166              33,506
                                                                                            -------             ------
                           Total Liabilities                                                59,281              55,241
                                                                                            -------             ------       
                                                                                                   
                MINORITY INTEREST IN AFFILIATES                                              3,258               3,336
                                                                                             -------             ------      
                COMMITMENTS AND CONTINGENCIES (NOTE 14)                                            
                                                                                                   
                PARTNERS' CAPITAL                                                                  
                                                                                                   
                   Class A Units - 9,977,254 Units issued, 9,077,949                               
                       outstanding in 1997 and 1996                                         66,184              61,487
                   Class B Subordinated Units - 143,773 Units issued                               
                       and outstanding in 1997 and 1996                                      1,411               1,254
                   Class C Units - 664,063 Units issued and outstanding in                         
                       1997 and 1996                                                         4,868               5,146
                   General Partner                                                           3,580               3,307
                      Treasury Units - 899,305 Units in 1997 and 1996                       (6,979)             (6,979)
                                                                                             -------             ------ 
                           Partners' Capital - Net                                          69,064              64,215
                                                                                            -------             ------
                                                                                                   
                                                                                                   
                                                                                                   
                TOTAL LIABILITIES AND PARTNERS' CAPITAL                                   $131,603             $122,792
                                                                                          ========             ========







<FN>

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


<PAGE>

<TABLE>
<CAPTION>

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

                                                                            For the Years Ended December 31,
                                                                         1997              1996             1995
                                                                   -     -----       -     -----       -    ----

       REVENUES:
<S>                                                                    <C>              <C>              <C>      
          Oil revenue                                                  $  14,690        $  19,534        $  17,240
          Gas revenue                                                     27,220           28,618           23,770
          Pipeline, facilities and other                                   2,797            2,492            2,444
          Interest                                                           396              422              326
                                                                         -------           -------           -----
                                                                                  
                                                                          45,103           51,066           43,780
                                                                         -------           -------           ----- 
       EXPENSES:                                                                 
          Production operating                                            11,060           11,511           11,298
          Facilities operating                                               641              726              794
          General and administrative                                       5,333            4,540            5,580
          Depreciation, depletion and amortization                        11,961           13,500           15,827
          Impairment of oil and gas properties                                                              10,943
          Interest                                                         3,096            3,878            4,245
                                                                          -------           -------           -----
                                                                          32,091           34,155           48,687
                                                                         -------           -------           -----
       OTHER INCOME (EXPENSES):                                                  
          Equity in earnings (loss) of HCRC                                1,348            1,768            (2,273)
          Minority interest in net income of affiliates                   (1,797)           (2,723)          (1,465)
          Litigation settlement                                              240              (230)            (386)
                                                                          -------           -------           ----- 
                                                                            (209)           (1,185)          (4,124)
                                                                          -------           -------           ----- 
       NET INCOME (LOSS)                                                  12,803           15,726            (9,031)
       CLASS C UNIT DISTRIBUTIONS ($1.00 PER UNIT)                           664              664
                                                                          -------           -------           ----- 
       NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL PARTNER, CLASS                  
          A AND CLASS B LIMITED PARTNERS                               $  12,139        $  15,062         $  (9,031)  
          CLASS B LIMITED PARTNERS                                      ========           ========          ========            
                                                                                           
       ALLOCATION OF NET INCOME (LOSS):
                                                                       
       General partner                                                $   2,097          $   2,569        $   1,289
                                                                                           ========         ========
                                                                                    
       Class A and Class B Limited partners                            $ 10,042           $ 12,493           $(10,320)
                                                                         ======             =======            =======
          Per Class A Unit and Class B Unit - basic                  $     1.09         $     1.35         $    (1.07)
                                                                        =======           =========          =========
          Per Class A Unit and Class B Unit - diluted                $     1.07          $     1.35        $    (1.07)
                                                                        =======            =========          =========
          Weighted average Class A Units and Class B              
             Units outstanding                                          9,222                  9,240            9,683
                                                                      ========                 ========         =====
                                                                     

<FN>

               The accompanying notes are an integral part of the
                             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

<S>                                    <C>               <C>               <C>              <C>                 <C>       
Balance, December 31, 1994             $  4,051          $  77,342         $  1,350                              $  (3,940)
Increase in Treasury Units                                                                                          (2,145)
Syndication costs                                              (63)
Distributions                            (2,359)            (7,517)            (116)
Net income (loss)                         1,289            (10,148)            (172)
                                          -----            -------             ----

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

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

Balance, December 31, 1997              $ 3,580            $ 66,184           $1,411             $4,868             $(6,979)
                                         ======              ======            =====              =====              ======










<FN>


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


<PAGE>

<TABLE>
<CAPTION>

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


                                                                       For the Years Ended December 31,
                                                              1997            1996             1995
                                                              ----        -   -----       -    ----

OPERATING ACTIVITIES:
                                                        
<S>                                                      <C>               <C>              <C>      
   Net income (loss)                                     $ 12,803          $ 15,726         $ (9,031)
   Adjustments to reconcile net income (loss) to                  
   net cash provided by operating activities:                       
        Depreciation, depletion, amortization and                  
           impairment                                      11,961            13,500           26,770
        Depreciation charged to affiliates                    221               265              256
        Amortization of deferred loan costs and                    
        other assets                                           81               167              201
        Noncash interest expense                              241               219              289
        Minority interest in net income                     1,797             2,723            1,465
        Take-or-pay recoupment                               (126)             (376)            (571)
        Equity in (earnings) loss of HCRC                  (1,348)           (1,768)           2,273
        Undistributed (earnings) loss of affiliates           197              (187)            (886)
   Changes in operating assets and liabilities                    
   provided (used) cash net of noncash activity:                         
        Oil and gas revenues receivable                       633            (2,638)            (547)
        Trade receivables                                    (102)           (1,647)             182
        Due from affiliates                                (2,948)            2,808           (1,161)
        Prepaid expenses and other current assets            (623)              163              261
        Accounts payable and accrued liabilities            4,730            (2,159)          (1,052)
        Due to affiliates                                    (133)             (373)
                                                           ------            ------           ------
           Net cash provided by operating activites        27,384            26,423           18,449
                                                           ------           ------            ------
INVESTING ACTIVITIES:                                             
   Additions to property, plant and equipment              (3,233)           (3,148)          (2,727)
   Exploration and development costs incurred             (12,983)           (9,467)          (8,404)
   Proceeds from sales of property, plant and equipment       133             5,294              394
   Investment in affiliates                                   (76)             (449)
   Refinance of Spraberry investment                                         (4,715)
   Other investing activities                                 (29)
                                                           ------            -------          -------
           Net cash used in investing activities          (16,188)          (12,485)         (10,737)
                                                           -------          -------          -------
                                                                  
FINANCING ACTIVITIES:                                             
   Payments of long-term debt                              (7,285)          (11,373)          (7,379)
   Proceeds from long-term debt                             7,000             9,000           15,000
   Distributions paid                                      (7,676)           (8,176)         (10,020)
   Distributions paid by consolidated affiliates to                
     minority interest                                     (1,875)           (2,429)          (1,346)
   Payment of contract settlement                                              (305)          (1,336)
   Other financing activities                                (278)              (92)             (63)
                                                            ------              ---            -----
           Net cash used in financing activities          (10,114)          (13,375)          (5,144)
                                                           -------          -------           ------
NET INCREASE IN CASH AND CASH                                      
   EQUIVALENTS                                              1,082               563            2,568
                                                                  
CASH AND CASH EQUIVALENTS:                                        
                                                                   
   BEGINNING OF YEAR                                        5,540             4,977            2,409
                                                            ------            -----            -----
   END OF YEAR                                          $   6,622         $   5,540        $   4,977
                                                          ========         ========         ========

<FN>

               The accompanying notes are an integral part of the
                             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

HEP has entered into numerous 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.

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,  1997,  HEP had a net  over-produced  position of 162,000 mcf
($374,000 valued at average gas prices).  The general partner believes that this
imbalance can be made up from or repaid by production on existing  wells or from
wells which will be drilled as offsets to existing wells and that this imbalance
will not have a material  effect on HEP's results of  operations,  liquidity and
capital resources.  HEP's oil and gas reserves as of December 31, 1997 have been
decreased by 162,000 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.

<TABLE>
<CAPTION>

                                                  Unitholders         General Partner



 Property Costs and Revenues
   Initial acquisition costs -
<S>                                                    <C>                      <C>
      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%

<FN>

    (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.
</FN>
</TABLE>

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.

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.

Deferred Liability

The deferred  liability as of December 31, 1997 and 1996  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, 1998 to Unitholders of record on December 31, 1997. This amount and
the general  partner  distribution  were accrued as of year end. At December 31,
1997 and 1996, distributions payable of $2,093,000 and $1,996,000,  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 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
effect of its  activities  accrues to the  partners.  In certain  circumstances,
partnerships  may be  held  to be  associations  taxable  as  corporations.  The
Internal Revenue Service has issued regulations  specifying  circumstances under
current  law when such a finding may be made,  and  management  has  obtained an
opinion of counsel  based on those  regulations  that HEP is not an  association
taxable as a  corporation.  A finding  that HEP is an  association  taxable as a
corporation could have a material adverse effect on the financial position, cash
flows and results of operations of HEP.

As a result of 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,  1997  and  1996,  the  income  tax  bases  of  the
Partnership's  oil  and  gas  properties  were  approximately   $94,000,000  and
$94,400,000, 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

During February 1997, the Financial  Accounting Standards Board issued Statement
of Financial  Accounting Standards No. 128 Earnings per Share ("SFAS 128"). SFAS
128 establishes standards for computing and presenting earnings per share (EPS),
and supersedes APB Opinion No. 15 and its related  interpretations.  It replaces
the presentation of primary EPS with a presentation of basic EPS, which excludes
dilution,  and  requires  dual  presentation  of basic and  diluted  EPS for all
entities with complex capital  structures.  Diluted EPS is computed similarly to
fully  diluted EPS pursuant to Opinion No. 15. SFAS 128 is effective for periods
ending  after  December  15,  1997,  including  interim  periods,  and  requires
restatement  of all  prior  period  EPS data  presented.  HEP  adopted  SFAS 128
effective  December  31,  1997,  and has  restated  all  prior  period  EPS data
presented to give retroactive effect to the new accounting standard.


<PAGE>


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 9, computed  using the treasury  stock
method which  assumes that the increase in the number of Units is reduced by the
number of Units which could have been  repurchased by the  Partnership  with the
proceeds from the exercise of the options  (which were assumed to have been made
at the average  market price of the Class A Units during the reporting  period).
All Unit and per Unit  information  has been restated to reflect the issuance of
Class A Units in connection with a lawsuit  settlement further described in Note
12.

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.
Unit options have been ignored in the  computation  of diluted loss per share in
1995 because their inclusion would be anti-dilutive.
<TABLE>
<CAPTION>

                                                                        Income           Units          Per Unit
                                                                           (In thousands except per Unit)

For the Year Ended December 31, 1997
<S>                                                                  <C>                 <C>              <C>   
   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
                                                                      =======            =====             =====

For the Year Ended December 31, 1995
   Net loss per Class A Unit and Class B Unit - basic                $(10,320)           9,683           $(1.07)
                                                                      -------            -----            =====
     Net loss per Class A Unit and Class B Unit - diluted            $(10,320)           9,683           $(1.07)
                                                                      =======            =====            =====
</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 899,305  of its own Units at  December  31,  1997 and 1996.  These  Units are
treated as treasury Units in the accompanying financial statements.

Use of Estimates

The  preparation of the financial  statements for the  Partnership in conformity
with  generally  accepted  accounting  principles  requires  management  to make
estimates  and  assumptions  that  affect  the  reported  amounts  of assets and
liabilities  and disclosure of contingent  assets and liabilities at the date of
the  financial  statements  and the  reported  amounts of revenues  and expenses
during the reporting period. Actual results could differ from these estimates.



<PAGE>


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, 1997, 1996
and 1995, purchases by the following companies exceeded 10% of the total oil and
gas revenues of the Partnership:

<TABLE>
<CAPTION>

                                                     1997              1996             1995
                                                     ----              ----             ----

                                                     
<S>                                                   <C>               <C>              <C>
Conoco Inc.                                           20%               28%              30%
Marathon Petroleum Company                            16%               11%              14%
El Paso Field Services Company                        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,  1997,  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.

Recently Issued Accounting Pronouncements

In June 1997,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial Accounting Standards No. 130 "Reporting  Comprehensive  Income" ("SAFS
130"). SAFS 130 established 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  is  required  to  adopt  SFAS  130 on  January  1,  1998.  The
Partnership  has not completed  the process of  evaluating  the impact that will
result from  adopting  SFAS 130 or the manner that will be used to disclose  the
required information in its financial statements.

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 certain cost information related to HEP's oil and
gas activities:

<TABLE>
<CAPTION>

                                                        For the Years Ended December 31,
                                                1997              1996             1995
                                      -         -----  -          -----  -         ----
                                                               (In thousands)

Property acquisition costs:
<S>                                             <C>             <C>              <C>    
   Proved                                       $ 1,942         $ 2,321          $ 2,727
   Unproved                                       1,071             560              793
Development costs                                 7,607           8,218           11,333
Exploration costs                                 6,950           2,200            2,915
                                                  -------         -----            -----
                                                       
      Total                                     $17,570         $13,299          $17,768
                                                 ======          ======           ======
</TABLE>

Depreciation,  depletion,  amortization and impairment expense related to proved
oil and gas properties,  per equivalent barrel of production for the years ended
December 31, 1997, 1996 and 1995, was $4.38, $4.35 and $7.21, respectively.

At December 31, unproved properties consist of the following:


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

Texas                                                    $    982       $1,062
California                                                    447 
North Dakota                                                  314 
Other                                                         571          182
                                                           -------       ------
                                                           $2,314        $1,244
                                                            =====         =====
                                                                               
NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES

On July 1, 1996, HEP and HCRC completed a transaction  involving the acquisition
from Fuel Resources Development Co., a wholly owned subsidiary of Public Service
Company of Colorado, and other interest owners of their interests in 38 coal bed
methane wells located in LaPlata  County,  Colorado and Rio Arriba  County,  New
Mexico.  Thirty-four of the wells, were assigned to 44 Canyon LLC ("44 Canyon"),
a special purpose entity owned by a large east coast financial institution.  The
wells qualify for tax credits under Section 29 of the Internal Revenue Code. HPI
manages and operates the  properties  on behalf of 44 Canyon.  The $28.4 million
purchase  price  was  funded  by 44  Canyon  through  the  sale of a  volumetric
production  payment to an affiliate of Enron Capital & Trade Resources  Corp., a
subsidiary of Enron Corp.,  the sale of a  subordinated  production  payment and
certain  other  property  interests for $3.45 million to an affiliate of HEP and
HCRC, and additional cash contributed by the owners of 44 Canyon.  The affiliate
of HEP and HCRC which purchased the  subordinated  production  payment and other
property  interests is owned equally by HEP and HCRC.  The interests in the four
wells in Rio Arriba County were acquired directly by HEP and HCRC.

During 1997 and 1995, HEP had no individually  significant property acquisitions
or sales.




<PAGE>


NOTE 4  -  DERIVATIVES

HEP has entered into numerous 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 a 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.

The following table provides a summary of HEP's financial contracts:
<TABLE>
<CAPTION>


                                                                                 Oil

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

<S>                      <C>                                     <C>                         <C>   
                         1995                                    380,000                     $17.41
                         1996                                    300,000                      18.33
                         1997                                    346,000                      17.78
                         1998                                    175,000                      16.62
                         1999                                     16,000                      15.38
</TABLE>

From 1998  forward,  between 9% and 100% of the oil volumes  hedged in each year
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.  From 1998  forward,  between 59% and 100% of the 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 prices range from $17.00
to $18.85.

<TABLE>
<CAPTION>

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

<S>                          <C>                                         <C>                         <C>  
                             1995                                        6,439,000                   $1.94
                             1996                                        5,479,000                    1.94
                             1997                                        5,386,000                    1.97
                             1998                                        4,835,000                    2.04
                             1999                                        2,460,000                    1.87
                             2000                                        1,244,000                    2.01
                             2001                                          272,000                    1.55
</TABLE>


From 1998 forward, between 0% and 38% 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 is $2.93 per mcf. In the event
of  nonperformance  by the  counterparties  to the financial  contracts,  HEP is
exposed to credit loss,  but has no off-balance  sheet risk of accounting  loss.
The  Partnership  anticipates  that the  counterparties  will be able to satisfy
their  obligations  under the contracts  because the  counterparties  consist of
well-established banking and financial institutions which have been in operation
for many years. Certain of HEP's hedges are secured by the lien on HEP's oil and
gas properties which also secures HEP's Credit Facilities described in Note 6.


NOTE 5  -  INVESTMENT IN AFFILIATED CORPORATION

HEP accounts for its approximate 46% interest in HCRC using the equity method of
accounting.  The following presents summarized financial information for HCRC at
December 31, 1997, 1996 and 1995:

<TABLE>
<CAPTION>

                                                             1997                  1996                  1995
                                              -              -----  -              -----  -              ----

                                                                               (In thousands)


                                                           
<S>                                                          <C>                 <C>                   <C>    
Current assets                                               $15,874             $10,802               $ 8,312
Noncurrent assets                                             76,497              67,666                65,627
Current liabilities                                           10,043              10,849                15,514
Noncurrent liabilities                                        32,678              24,558                21,790
Revenue                                                       32,411              34,445                25,484
Net income (loss)                                              5,585               8,160               (4,670)
</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,

                                                             1997                  1996                  1995
                                              -              -----  -              -----  -              ----

<S>                                                        <C>               <C>                   <C>        
Unproved properties                                        $     1,040       $       573           $       230
Proved properties                                              118,966           113,085                94,925
Accumulated depreciation, depletion,                                   
   amortization and property impairment                       (92,511)           (89,175)              (74,168)
                                                              --------           -------               -------
Net property                                                $   27,494         $  24,483             $  20,987
                                                              ========          ========              ========
</TABLE>



<PAGE>

<TABLE>
<CAPTION>

Costs Incurred in Oil and Gas Activities:


                                                                 For the Years Ended December 31,

                                                             1997                  1996                  1995
                                              -              -----  -              -----  -              ----


<S>                                                        <C>                    <C>                   <C>   
Acquisition costs                                          $1,303                 $1,008                $4,168
Development costs                                           2,060                  3,670                 2,124
Exploration costs                                           2,851                    382                   845
                                                            -----                    ---                   ---
     Total                                                 $6,214                  $5,060                $7,137
                                                            =====                  =====                 =====
</TABLE>

Results of Operations for Oil and Gas Activities:
<TABLE>
<CAPTION>
                                                                     For the Years Ended December 31,
                                                           1997               1996                     1995
                                              -            -----    -         -----                    ----

                                                        
<S>                                                          <C>              <C>                  <C>     
Oil and gas revenue                                          $10,889          $11,690              $  7,825
Production operating expense                                 (3,746)           (3,790)               (2,894)
Depreciation, depletion, amortization                               
   and property impairment expense                           (3,336)           (3,257)               (2,792)
Income tax benefit (expense)                                   (761)               23                  (813)
                                                             --------           -----                 ------
      Net income from oil and gas                       
        activities                                         $  3,046           $  4,666              $  1,326
                                                            =======            =======               =======
</TABLE>

                                                             
Proved Oil and Gas Reserve Quantities:


                                            Gas                  Oil
                                            Mcf                  Bbl

                                                    (unaudited)


Balance, December 31, 1997                27,268                 2,065
                                          ======                 =====
Balance, December 31, 1996                22,786                 2,680
                                          ======                 =====
Balance, December 31, 1995                15,782                 2,482
                                          ======                 =====

Standardized Measure of Discounted Future Net Cash Flows:


                                  (unaudited)

   December 31, 1997               $ 31,245
                                    =======
   December 31, 1996                $47,701
                                     ======
   December 31, 1995                $25,532
                                     ======



<PAGE>


NOTE 6  -  DEBT

HEP's long-term debt at December 31, 1997 and 1996 consisted of the following:


                                                  1997            1996
                                                  ---- -          ----

                                                            (In thousands)


                                                                
Note Purchase Agreement                         $  4,286        $  8,571
Credit Agreement                                  30,700          26,700
                                                  ------          ------
Total                                             34,986          35,271
Less current maturities                                           (5,810)
                                                  ------          ------ 
Long-term debt                                    $34,986         $29,461
                                                  =======         =======  
                                                  
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 line of credit to May 31,  1999.  Under the  Credit
Agreement and an Amended and Restated Note Purchase  Agreement  ("Note  Purchase
Agreement")  (collectively  referred to as the "Credit  Facilities"),  HEP has a
borrowing base of $46,000,000.  HEP has amounts outstanding at December 31, 1997
of $30,700,000 under the Credit Agreement and $4,286,000 under the Note Purchase
Agreement.  Subsequent  to December  31,  1997,  HEP repaid  $14,000,000  of its
borrowings  under the  Credit  Agreement  and  repaid  its  contract  settlement
obligation  of  $2,752,000;  therefore,  HEP's  unused  borrowing  base  totaled
$25,014,000 at February 27, 1998.

Borrowings under the Note Purchase  Agreement bear interest at an annual rate of
11.85%,  which is payable  quarterly.  Annual  principal  payments of $4,286,000
began April 30,  1992,  and the debt is required to be paid in full on April 30,
1998.  HEP  intends to fund the  payment  due in April 1998  through  additional
borrowings under the Credit  Agreement;  thus, no portion of HEP's Note Purchase
Agreement is classified as current as of December 31, 1997.

Borrowings  against  the  Credit  Agreement  bear  interest  at the lower of the
Certificate  of Deposit rate plus from 1.375% to 1.875%,  prime plus 1/2% or the
Euro-Dollar  rate plus from 1.25% to 1.75%.  At December 31, 1997 the applicable
interest rate was 7.5%. Interest is payable monthly,  and 16 quarterly principal
payments of $2,187,000,  as adjusted for the anticipated  borrowings to fund the
Note Purchase Agreement payment due in 1998, commence May 31, 1999.

The borrowing base for the Credit Facilities is redetermined  semiannually.  The
Credit  Facilities are secured by a first lien on approximately  80% in value of
HEP's oil and gas properties.  Additionally, aggregate distributions paid by HEP
in any 12 month  period are limited to 50% of cash flow from  operations  before
working capital changes 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.

HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for each of 1997 and 1998 and  $10,000,000  for each of 1999 and  2000.
HEP does not use the hedges for trading purposes,  but rather for the purpose of
providing a measure of  predictability  for a portion of HEP's interest payments
under its debt agreement,  which has a floating interest rate. In general, it is
HEP's  goal to hedge  50% of the  principal  amount of its debt for the next two
years and 25% for each year of the remaining  term of the debt.  HEP has entered
into four hedges, one


<PAGE>


of which is an interest  rate  collar  pursuant to which it pays a floor rate of
7.55% and a ceiling rate of 9.85%,  and the others are interest  rate swaps with
fixed  rates  ranging  from 5.75% to 6.57%.  The  amounts  received or paid upon
settlement of these  transactions are recognized as interest expense at the time
the  interest  payments  are due.  At December  31,  1997,  HEP's debt  maturity
schedule is as follows:


                       (In thousands)

1998                       $ 
1999                         6,561
2000                         8,748
2001                         8,748
2002                         8,748
Thereafter                   2,181
                           -------
   Total                   $34,986
                          ========


NOTE 7  -  CONTRACT SETTLEMENT OBLIGATION

In the first quarter of 1989,  HEP settled a take-or-pay  contract  claim on its
Bethany-Longstreet  field.  In  accordance  with the  settlement,  HEP  received
$7,623,000 in cash. This amount was recoupable in cash or gas volumes from April
1992  through  March  1996,  with a cash  balloon  payment  due during the first
quarter of 1998. A liability  has been  recorded  equal to the present  value of
this amount discounted at 10.68%,  HEP's estimated borrowing cost at the time of
settlement.  HEP also repaid $1,629,000 which represented  suspended payments to
the pipeline for previous years in equal monthly  installments  of $33,937 which
began April 1992 and continued  through March 1996.  This amount was  previously
recorded  as an  offset  to the full  cost  pool at the time  the  contract  was
initially  abrogated by the pipeline.  As payment of this obligation was made it
was charged to the full cost pool.

At December 31, 1997,  the current  contract  settlement  balance  consists of a
payment of  $2,767,000  due in  February  1998,  net of  unaccreted  discount of
$15,000.


NOTE 8  -  PARTNERS' CAPITAL

HEP Units that trade on the American  Stock  Exchange under the symbol "HEP" are
referred to as "Class A Units," and Units that trade under the symbol "HEPC" are
referred to as "Class C Units".

Class B Subordinated Units

The Class B Units have equal  liquidation  rights and identical  tax  allocation
rights and provisions to the Class A Units.  However, the Class B Units have the
following subordinated distribution provisions:

1.   Distribution  rights equal to Class A Units while the Class A Units receive
     distributions of $.20 or more per Class A Unit per calendar quarter.

2.   No current  distribution  right should Class A Units receive  distributions
     less than $.20 per Class A Unit for any calendar quarter.

3.   An accumulated  distribution  deficit account is maintained for the benefit
     of the Class B Units for any  distributions  suspended  under 2 above.  The
     amount in the deficit account is payable in whole or in part to the Class B
     Unitholders in any quarter in which  distributions equal to or greater than
     $.20 per Class A Unit are made on Class A Units.
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 9  -  EMPLOYEE INCENTIVE PLANS

Every year beginning in 1992, the Board of Directors of the general  partner has
adopted an  incentive  plan.  Each year the Board of  Directors  determines  the
percentage  of HEP's  interest  in the cash flow  from  certain  wells  drilled,
recompleted or enhanced during the year allocated to the incentive plan for that
year. The specified  percentage was 2.4% for 1997 and 1996 and 1.4% for domestic
wells for 1995. In 1995,  HEP also had an  international  incentive plan and the
percentage  interest in cash flow for that plan was 3%.  Beginning in 1996,  the
domestic and international plans were combined. The specified percentage of cash
flow is then allocated  among certain key employees who are  participants in the
Plan  for that  year.  Each  award  under  the plan  (with  regard  to  domestic
properties)  represents  the right to  receive  for five  years a portion of the
specified share of the cash award,  at the conclusion of which the  participants
are each  paid a share of an amount  equal to a  specified  percentage  (80% for
1997, 1996 and 1995) of the remaining net present value of the qualifying wells,
and the award for that year terminates.  The expenses  attributable to the plans
were $277,000 in 1997, $148,000 in 1996 and $119,000 in 1995 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 Unit Option Plan ("Option  Plan") to be used for the  motivation
and retention of directors,  employees and consultants  performing  services for
HEP. The plan  authorizes  the issuance of options to purchase  425,000  Class A
Units.  Grants of the total  options  authorized  were made on January 31, 1995,
vesting one-third at that time, an additional  one-third on January 31, 1996 and
the remaining  one-third on January 31, 1997.  The exercise price of the options
is $5.75, which was the closing price of the Class A Units on January 30, 1995.

A summary  of options  granted  under the Option  Plan and the  changes  therein
during the years ended December 31, 1997, 1996 and 1995 is presented below:



<PAGE>


<TABLE>
<CAPTION>


                                                  1997                        1996                         1995
                                                                                                               
                                                         Weighted                    Weighted                    Weighted
                                                         Average                     Average                     Average
                                                         Exercise                    Exercise                    Exercise
                                            Units         Price         Units         Price         Units         Price

<S>                                      <C>             <C>          <C>            <C>          <C>             <C>
  Outstanding at beginning of year       425,000         $5.75        425,000        $5.75
  Granted                                                                                         425,000         $5.75
                                         ------------- --------      -------------- --------      -------          ----
  Outstanding at end of year              425,000         $5.75        425,000        $5.75       425,000         $5.75
                                          =======          ====        =======         ====       =======          ====

  Options exercisable at year end         425,000         $5.75        283,330        $5.75       141,665         $5.75
                                          =======          ====        =======         ====       =======          ====
</TABLE>


The  Partnership  has adopted the  disclosure-only  provisions  of  Statement of
Financial   Accounting   Standards   No.  123,   "Accounting   for   Stock-Based
Compensation"  ("SFAS  123").   Accordingly,   no  compensation  cost  has  been
recognized  for the Option Plan.  Had  compensation  expense for the Option Plan
been  determined  based on the  fair  value at the  grant  date for the  options
awarded in 1995  consistent  with the  provisions of SFAS 123,  HEP's net income
(loss) and net income  (loss) per Unit would have been  reduced to the pro forma
amounts indicated below:

<TABLE>
<CAPTION>

                                                              1997                   1996                   1995
                                                              ----                   ----                   ----
<S>                                                     <C>                         <C>                 <C>         
Net income (loss):  as reported                         $12,803,000                 $15,726,000         $(9,031,000)
                    pro forma                            12,730,000                  15,544,000          (9,432,000)
                                                                                            
Net income (loss)                                                                           
  per Class A and B Unit - basic:                                                           
                            as reported                   $1.09                       $1.35              $(1.07)
                            pro forma                     $1.08                        1.33              $(1.11)
                                                                                            
Net income (loss)                                                                           
  per Class A and Class B Unit - diluted                  
                            as reported                   $1.07                       $1.35              $(1.07)
                            pro forma                     $1.07                       $1.33              $(1.11)

</TABLE>

                                                                  
The fair value of the Unit options for disclosure  purposes was estimated on the
date of the grant using the Binomial  Option  Pricing  Model with the  following
assumptions:


Expected dividend yield                                       6%
Expected price volatility                                   28%
Risk-free interest rate                                       7.6%
Expected life of options                                    10 years


NOTE 10 - RELATED PARTY TRANSACTIONS

HPI manages and operates certain oil and gas properties on behalf of independent
joint interest owners,  HEP and its affiliates.  In such capacity,  HPI pays all
costs and expenses of operations and  distributes  all revenues  associated with
such  properties.  HPI has  receivables  from  affiliates  of HEP of $588,000 at
December 31, 1997 and payables to  affiliates of HEP of $159,000 at December 31,
1996,  which  represent net revenues net of operating  costs and  expenses.  The
intercompany balances are settled monthly.

HPI is  reimbursed  by HEP for costs and expenses  which  includes  office rent,
salaries and associated overhead for personnel of HPI engaged in the acquisition
and  evaluation  of oil and gas  properties  (technical  expenditures  which are
capitalized as costs of oil and gas  properties) and lease operating and general
and   administrative   expenses   necessary  to  conduct  the  business  of  HEP
(nontechnical  expenditures  which are expensed as general and administrative or
production operating expenses).  Reimbursements  during 1997, 1996 and 1995 were
as follows:

<TABLE>
<CAPTION>

                                             1997                 1996                  1995
                             -               ----  -              -----  -              ----
                                                   (In thousands)
                                            
<S>                                          <C>                 <C>                   <C>   
Technical                                    $966                $1,249                $1,100
Nontechnical                                  896                 1,110                 1,321

</TABLE>

                                            
Included in the  nontechnical  allocation  attributable to HEP's direct interest
for  1997,  1996 and 1995 is  approximately  $275,000,  $152,000  and  $156,000,
respectively,  of  consulting  fees under a consulting  agreement  with Hallwood
Group.  Also included in the nontechnical  allocation is $301,000,  $309,000 and
$369,000 in 1997, 1996 and 1995,  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.  This agreement was terminated  effective  December 1996. The
amount of consulting fees allocated to the Partnership  under this agreement was
$125,000 in both 1996 and 1995.


NOTE 11 - STATEMENT OF CASH FLOWS

Cash paid during 1997,1996 and 1995 for interest totaled $2,775,000,  $3,492,000
and $3,356,000, respectively.


NOTE 12 - LITIGATION SETTLEMENTS

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.  In  September  1995,  the court  order  approving  the
settlement in the class action lawsuit styled In re. Hallwood  Energy  Partners,
L.P. Securities Litigation became final. As part of the settlement, on September
28, 1995,  HEP paid  $2,870,000 in cash (which was recorded as an expense in the
December 31, 1994 financial statements as the estimated cost associated with the
litigation) and issued 1,158,696 Class A Units with a market value of $5,330,000
to a nominee of the class.  HCRC  subsequently  exercised  an option to purchase
these  Units  from  the  nominee  for  $5,330,000  in  cash.   Other  defendants
contributed an additional  $900,000 in cash to the settlement.  The net proceeds
of the settlement  were  distributed  to a class  consisting of former owners of
limited  partner  interests in Energy  Development  Partners,  Ltd.  ("EDP") who
exchanged  their units in that entity for Units of HEP pursuant to the merger of
EDP and HEP on May 9, 1990 (the "Transaction").

Upon  issuance,  these  Class A Units  were  treated,  for  financial  statement
purposes, as additional Class A Units issued in connection with the Transaction,
which was accounted for as a reorganization of entities under common control, in
a  manner  similar  to a  pooling  of  interest,  and  have  been  reflected  as
outstanding  Class A Units since May 9, 1990, the date of the Transaction.  As a
result of the  settlement,  the number of Units  outstanding  and the net income
(loss) per Class A Unit and Class B Unit have been  retroactively  restated  for
all periods subsequent to the Transaction date.


NOTE 13 - LEGAL PROCEEDINGS

On December 3, 1997,  Arcadia  Exploration  and Production  Company  ("Arcadia")
filed a Demand for Arbitration 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 herein as "Hallwood"), claiming that Hallwood breached
a Purchase and Sale Agreement dated August 25, 1997, between Arcadia and HEP and
HCRC.  Arcadia's  Demand  for  Arbitration  seeks  specific  performance  of the
agreement  which  Arcadia  claims  requires  Hallwood  to  purchase  oil and gas
properties from Arcadia for approximately  $27 million.  HEP and HCRC terminated
the agreement  because of environmental  and title problems with the properties.
Additionally,   Arcadia  seeks  incidental  and  special  damages,   prejudgment
interests and attorneys' fees and costs.  Hallwood filed its Answering Statement
and  Counterclaim  asserting that it properly  terminated  and/or  rescinded the
Agreement and seeking refund of Hallwood's  earnest money  deposit,  prejudgment
interest,  attorneys'  fees and costs.  HEP's  management  intends to vigorously
defend the claims  asserted  by Arcadia  and  intends to  vigorously  pursue the
counterclaim against Arcadia. This matter is currently in its preliminary stages
as  pre-hearing  discovery  has only just  commenced.  Thus,  it is too early to
predict the ultimate outcome of this arbitration proceeding.

Concise Oil and Gas Partnership  ("Concise"),  a wholly owned  subsidiary of the
Partnership,  is a defendant in a lawsuit styled Dr. Allen J.  Ellender,  Jr. et
al. vs. Goldking Production Company, et al., filed in the Thirty-Second Judicial
District Court, Terrebonne Parish,  Louisiana on May 30, 1996. The approximately
150 plaintiffs in this  proceeding are seeking  unspecified  damages for alleged
breaches of certain oil, gas and mineral leases in the Northeast Montegut Field,
Terrebonne Parrish,  Louisiana.  In addition,  they are asking for an accounting
from  Concise  for  production  of natural  gas for the period of time from 1983
through November 1987. Specifically,  as to the claims against Concise, the suit
alleges  that  Concise  failed to obtain  the  prices to which it was  allegedly
entitled  for  natural  gas sold in this  field in the 1980s  under a  long-term
natural gas sales  contract.  The  plaintiffs,  royalty and  overriding  royalty
owners,  allege that as a result of the alleged imprudent  marketing  practices,
they are  entitled  to their  share of the  prices  which  Concise  should  have
obtained.  Plaintiffs  have  also  sued  approximately  35 other  companies  and
individuals,  and allege that Concise is jointly and  severally  liable with the
rest of the  defendants for the claims raised by the  plaintiffs.  The judge has
recently  ruled  against  the  plaintiffs  on their  claim of joint and  several
liability,  and has also ruled that the  applicable  statute of  limitations  is
three years, rather than ten years as the


<PAGE>


plaintiffs  claimed.  The claims raised against the other defendants are similar
in substance to those raised against Concise, but seek damages and an accounting
for the period of time from 1983 until the present time. While the trial of this
case is  currently  set for  August  1998,  the trial  date will most  likely be
continued  beyond that date. The outcome of this litigation  cannot be predicted
with  certainty.  However,  the  Partnership  believes that the claims  asserted
against Concise are without merit and intends to vigorously defend against them.

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


NOTE 14 - COMMITMENTS

HPI leases office  facilities  under operating leases which expire in 1999. Rent
expense  under these leases is allocated  to HEP and its  affiliates.  Remaining
commitments under these leases mature as follows:


            Year Ending                        Annual Rentals
            December 31,                       (in thousands)

                1998                                 $632
                1999                                  316
                                                      ---
                                                     $948

Rent expense allocated to HEP was $288,000,  $304,000 and $299,000 for the years
ended December 31, 1997, 1996 and 1995, respectively.


NOTE 15 - ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is
made in accordance  with the  requirements of SFAS No. 107,  "Disclosures  about
Fair Value of Financial Instruments." The estimated fair value amounts have been
determined  by  the  Partnership,   using  available   market   information  and
appropriate   valuation   methodologies.   However,   considerable  judgment  is
necessarily  required in  interpreting  market data to develop the  estimates of
fair value.  Accordingly,  the estimates  presented  herein are not  necessarily
indicative of the amounts that the Partnership could realize in a current market
exchange.   The  use  of  different   market   assumptions   and/or   estimation
methodologies may have a material effect on the estimated fair value amounts.

<TABLE>
<CAPTION>

                                                                          December 31, 1997
                                                                Carrying                 Estimated Fair
                                                                 Amount                        Value
                                                                           (In thousands)

Liabilities:
<S>                                                          <C>      <C>                   <C>      
  Interest rate hedge contracts                              $       -0-                    $     186
  Oil and gas hedge contracts                                        -0-                        1,029
  Current portion of contract settlement                           2,752                        2,752
  Long-term debt                                                  34,986                       34,986
</TABLE>



<PAGE>


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.

The current  portion of the contract  settlement is carried in the  accompanying
balance sheets at an amount which is a reasonable estimate of its fair value.

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, 1997.  Although  management  is not
aware of any factors that would  significantly  affect the estimated  fair value
amounts,  such  amounts have not been  comprehensively  revalued for purposes of
these financial  statements since that date, and current estimates of fair value
may differ significantly from the amounts presented herein.


NOTE 16 - SUBSEQUENT EVENT

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 discounts
and expenses,  were approximately  $16,315,000.  HEP used $14,000,000 of the net
proceeds  to repay  borrowings  under  its  Credit  Agreement  and  applied  the
remaining  net  proceeds  toward the  repayment  of HEP's  outstanding  contract
settlement obligation of $2,752,000.



<PAGE>


                         HALLWOOD ENERGY PARTNERS, L.P.
                  SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
                                DECEMBER 31, 1997
                                   (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.  At
December 31, 1997, oil and gas prices  averaged  $16.90 per bbl of oil and $2.30
per  mcf  of gas  for  HEP,  including  its  indirect  interests  in  affiliated
partnerships and the Mays.  Future  production costs are based on year end costs
and include  severance  taxes. The present value of future cash inflows is based
on a 10% discount rate. The reserve  calculations  using these December 31, 1997
prices result in 5.8 million bbls of oil, and 93.1 billion cubic feet of gas and
a standardized measure of $129,000,000.  The Mays are included on a consolidated
basis, and 53,000 bbls of oil and 1.5 billion cubic feet of gas,  representing a
discounted  present  value  of  $3,700,000  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 200,000 bbls of
oil and 6 billion cubic feet of gas with a  standardized  measure of $10,000,000
at December 31, 1997.

HEP's  standardized  measure  of future  net cash  flows has been  decreased  by
$2,620,000  at December  31, 1997 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, 1994                                                       85,585                 6,738

   Extensions and discoveries                                                        5,997                 1,902
   Revisions of previous estimates                                                   4,248                   464
   Sales of reserves in place                                                          (45)                  (41)
   Purchase of reserves in place                                                       362                    28
   Production                                                                      (13,035)                 (993)
                                                                                   -------                  ----


   Balance, December 31, 1995                                                       83,112                 8,098

   Extensions and discoveries                                                        1,683                   484
   Revisions of previous estimates                                                  10,552                   385
   Sales of reserves in place                                                       (3,369)                 (481)
   Purchase of reserves in place                                                     9,350                    17
   Production                                                                      (12,786)                 (972)
                                                                                   -------                  ----

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

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


   Balance, December 31, 1997                                                       93,053                 5,767
                                                                                    ======                 =====
Proved Developed Reserves:
   Balance, December 31, 1995                                                       73,378                 7,444
                                                                                    ======                 =====
   Balance, December 31, 1996                                                       85,848                 7,056
                                                                                    ======                 =====
   Balance, December 31, 1997                                                       89,816                 5,181
                                                                                    ======                 =====
</TABLE>



<PAGE>

<TABLE>
<CAPTION>

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



                                                                                December 31,
                                                                                ------------
                                                              1997                   1996                   1995
                                                              ----                   ----                   ----

<S>                                                         <C>                    <C>                   <C>       
Future cash flows                                           $  293,000             $  509,000            $  317,000
Future production and development costs                       (115,000)              (175,000)             (130,000)
                                                               -------               --------              --------
Future net cash flows before discount                          178,000                334,000               187,000
10% discount to present value                                  (49,000)              (128,000)              (63,000)
                                                               -------               --------               -------
Standardized measure of discounted future net cash
    flows                                                   $  129,000             $  206,000            $  124,000
                                                             =========              =========             =========

</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 Years Ended December 31,
                                                                       --------------------------------
                                                              1997                   1996                   1995
                                                              ----                   ----                   ----

Standardized measure of discounted future net
<S>                                                           <C>                   <C>                   <C>     
  cash flows at beginning of year                             $206,000              $124,000              $104,000
Sales of oil and gas produced, net of production
  costs                                                        (30,209)              (35,915)              (29,712)
Net changes in prices and production costs                     (78,965)               75,085                17,015
Extensions and discoveries, net of future
  production and development costs                               9,592                 7,144                16,836
Changes in estimated future development costs                  (10,012)               (6,515)              (11,321)
Development costs incurred                                       7,607                 8,218                11,333
Revisions of previous quantity estimates                            (8)               20,032                 6,817
Purchases of reserves in place                                   1,457                14,721                   513
Sales of reserves in place                                        (204)               (9,742)                 (281)
Accretion of discount                                           20,600                12,400                10,400
Changes in production rates and other                            3,142                (3,428)               (1,600)
                                                                 -----                ------                ------
Standardized measure of discounted future net
  cash flows at end of year                                   $129,000              $206,000              $124,000
                                                               =======               =======               =======
</TABLE>

The standardized measure of discounted future net cash flows is calculated using
year end average oil and gas prices.  At December 31,  1997,  oil and gas prices
averaged  $16.90 per bbl of oil and $2.30 per mcf of gas. If average oil and gas
prices as of February 27, 1998 of $15.70 per bbl of oil and $2.10 per mcf of gas
had been used in this calculation, the standardized measure of discounted future
net cash flows would have been approximately 12% lower.


<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  operation  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, 53, 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,  54, has been  President  of Hallwood  G.P.  and HPI since
October 1989,  and a director of Hallwood G.P. and HPI since August 1989. He was
President,  Chief  Operating  Officer and a director of HEC from  February  1985
until November 1996. Mr. Guzzetti joined HEC in February 1976 as Vice President,
Secretary and General Counsel and served in these positions until November 1980.
He served as Senior Vice  President,  Secretary and General  Counsel of HEC from
November 1980 until February 1985, when he became President of HEC. Mr. Guzzetti
has been  President,  Chief  Operating  Officer and a director of HCRC since May
1991. Mr.  Guzzetti is also an Executive Vice President of Hallwood Group and in
that  capacity  may devote a portion of his time to the  activities  of Hallwood
Group,  including the management of real estate  investments,  acquisitions  and
restructurings  of entities  controlled by Hallwood  Group. He is a director and
President  of Hallwood  Realty and in that  capacity may devote a portion of his
time to the activities of Hallwood Realty.



<PAGE>


Russell P. Meduna,  43, has served as Executive  Vice President of Hallwood G.P.
and HPI since October 1989.  He was  Executive  Vice  President of HEC from June
1991 until  November 1996. He was Vice President of HEC from May 1990 until June
1991.  Mr.  Meduna became  Executive  Vice  President of HCRC in June 1992.  Mr.
Meduna was Vice  President  of Hallwood  G.P. and HPI from April 1989 to October
1989 and Manager of Operations from January 1989 to April 1989. He joined HPI in
1984 as Production Manager.  Prior to joining HPI, he was employed by both major
and independent oil companies.  Mr. Meduna is a registered professional engineer
in the States of Colorado and Texas.

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

Robert S.  Pfeiffer,  41, has served as Vice  President of Hallwood G.P. and HPI
since August 1986.  He was Vice  President of HEC from June 1991 until  November
1996. Mr. Pfeiffer  became Chief  Financial  Officer of HPI in June 1994. He has
been Vice  President of HPI since June 1992. He joined  Hallwood G.P. and HPI in
1984.  From July 1979 to May 1984,  he was  employed  by Price  Waterhouse  as a
senior  accountant.  Mr.  Pfeiffer  is a member  of the  American  Institute  of
Certified  Public  Accountants  and the  Colorado  Society of  Certified  Public
Accountants.  Mr.  Pfeiffer  resigned his  positions  with Hallwood G.P. and all
affiliated entities effective March 6, 1998.

Betty J. Dieter,  50, has been Vice  President of HPI  responsible  for domestic
operations  since January 1995.  Her previous  positions  with HPI have included
Operations  Manager,  Rocky  Mountain  and  Mid-Continent  District  Manager and
Manager for Operations  Accounting and  Administration.  She joined HPI in 1985,
and has 25 years experience in accounting and operations, 18 of which are in the
oil and gas industry. Ms. Dieter is a Certified Public Accountant.

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

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

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

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


<PAGE>


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

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

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, 1997,  all officers and  directors of Hallwood  G.P.,  Inc. and greater than
ten-percent beneficial owners complied with applicable filing requirements.


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 1997 the Partnership  reimbursed HPI for approximately
$1,286,000 of expenses,  of which $604,958 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,  1997)  for  services  to the  Partnership,  its
subsidiaries  and its General  Partner for the years ended  December  31,  1997,
1996, and 1995.


<PAGE>

<TABLE>
<CAPTION>

                                             Summary Compensation Table


                                                                            Long Term
                                             Annual Compensation           Compensation

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

<S>                               <C>          <C>          <C>              <C>         <C>               <C>         
Anthony J. Gumbiner (2).......    1997         $     0      $    0           (4)         $      0          $         0
         Chief Executive          1996         250,000           0            0                 0                    0
          Officer                 1995         250,000           0           (3)                0                    0

William L. Guzzetti...........    1997         204,294     143,870           (4)           42,854                4,750
         President and Chief      1996         204,294     131,500            0            33,170                5,699
         Operating Officer        1995         204,412      75,000           (3)           15,753                6,004

Russell P. Meduna.............    1997         163,664     111,520          (4)            42,854                4,750
         Executive Vice           1996         163,664     101,900            0            33,170                4,500
         President                1995         167,364     161,000           (3)           15,753                4,810

Robert S. Pfeiffer (5)            1997         107,518     102,880           (4)           30,124                4,750
         Vice President and       1996         107,518      56,700            0            23,092                4,300
         Chief Financial Officer  1995         109,949      94,000           (3)           11,692                3,160

Cathleen M. Osborn............    1997         105,685     100,000           (4)           30,124                4,750
         Vice President and       1996         105,685      62,400            0            23,092                4,500
         General Counsel          1995         109,069      95,000           (3)           11,692                3,160
----------------------
</TABLE>


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

(2)      For 1995 and 1996, Mr. Gumbiner had a Compensation  Agreement with HPI.
         $250,000  was  paid  under  this   agreement  in  1995  and  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 1995 and 1996, pursuant to which Hallwood Group
         received an annual  consulting fee of $300,000 from  affiliates of HPI.
         During 1997, 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.




<PAGE>


(3)      Consists of the following  options  granted in 1995.  The HCRC Options 
         have been adjusted to give effect to a 3-for-1 split effective in 1997.

<TABLE>
<CAPTION>

                                       Name                          Company         Securities Underlying
                                                                                        Options/SARs (#)

<S>                                                                                          <C>    
                  Anthony J. Gumbiner..........................   HEP                        127,500
                                                                  HCRC                        47,700
                  William L. Guzzetti..........................   HEP                         63,750
                                                                  HCRC                        23,850
                  Russell P. Meduna............................   HEP                         59,500
                                                                  HCRC                        22,260
                  Robert S. Pfeiffer...........................   HEP                         25,500
                                                                  HCRC                         9,540
                  Cathleen M. Osborn...........................   HEP                         25,500
                                                                  HCRC                         9,540
</TABLE>

(4)       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
 Robert S. Pfeiffer...........................                  9,540
 Cathleen M. Osborn...........................                  9,540

(5)  Mr. Pfeiffer resigned his positions with Hallwood G.P. and all affiliated 
     entities effective March 6, 1998.




<PAGE>


Option Grants and Exercises in Last Fiscal Year

The  following  table sets forth the  options to purchase  Common  Stock of HCRC
granted to  executive  officers  during  1997.  No options  granted to executive
officers were exercised in 1997.
<TABLE>
<CAPTION>

                                         Option/SAR Grants in Last Fiscal Year
                                                                                              Potential   Realized   Value  at
                                                                                              Assumed  Annual  Rates  of Stock
                                                                                              Price  Appreciation  for Option
                                                   Individual Grants                          Term (2)
                              Number of       % of Total
                              Securities     Options/SARs
                              Underlying        Granted        Exercise or                          5%               10%
                             Options/SARs    Employees in      Base Price       Expiration        $33.16           $52.73
                                Granted       Fiscal Year       ($/Share)            Date       Share Price      Share Price
                                 (1)
      Name

<S>                             <C>                 <C>        <C>            <C>   <C>           <C>             <C>       
Anthony J. Gumbiner             47,700              30         $20.33         06/17/07            $609,865        $1,545,517
William L. Guzzetti             23,850              15          20.33         06/17/07             304,932           772,759
Russell P. Meduna               22,260              14          20.33         06/17/07             284,604           742,242
Robert S. Pfeiffer(3)            9,540               6          20.33         06/17/07             121,973           309,104
Cathleen M. Osborn               9,540               6          20.33         06/17/07             121,973           309,104

</TABLE>


(1)      Options have a ten-year term and vest  cumulatively over three years at
         the  rate  of  1/3  on  each  of 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 HCRC.

(2)      Securities  and  Exchange   Commission  Rules  require  calculation  of
         potential realizable value assuming that the market price of the Common
         Stock  appreciates  in value at 5% and 10%  annualized  rates.  At a 5%
         annualized rate of appreciation, the Common Stock price would be $33.16
         at the end of ten years. At a 10% annualized rate of appreciation,  the
         Common Stock price would be $52.73 at the end of ten years.  No gain to
         an  executive  officer is possible  without an  appreciation  in Common
         Stock value, which will benefit all holders of Common Stock. The actual
         value an executive officer may receive depends on market prices for the
         Common Stock, and there can be no assurance that the amounts  reflected
         will actually be realized.

(3)      Mr. Pfeiffer resigned from HCRC effective March 6, 1998, and his 
         options terminated on that date.


<PAGE>


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

<TABLE>
<CAPTION>


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

<S>                                                  <C>       <C>                          <C>       <C>
     Anthony J. Gumbiner     HEP                     127,500 / 0                            334,688 / 0
                             HCRC                   63,600 / 31,800                       805,494 / 76,956

     William L. Guzzetti     HEP                      63,750 / 0                            167,344 / 0
                             HCRC                  31,800 / 15,900                        402,747 / 38,478

     Russell P. Meduna       HEP                      59,500 / 0                            156,188 / 0
                             HCRC                  29,680 / 14,840                        375,897 / 35,913

     Robert S. Pfeiffer      HEP                      25,500 / 0                             66,938 / 0
                             HCRC                   12,720 / 6,360                        161,099 / 15,391

     Cathleen M. Osborn      HEP                      25,500 / 0                             66,938 / 0
                             HCRC                   12,720/ 6,360                         161,099 / 15,391
</TABLE>

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

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

(2)      The  exercise  price of the HEP  options is $5.75 per Class A Unit. 
         The closing price of the Class A Units was $8.375 on December 31, 1997.

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

(4)      The  exercise  price of the HCRC  options  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 $22.25 on
         December 31, 1997. The exercise  prices have been adjusted to reflect a
         3-for-1 stock split effective in 1997.



<PAGE>


Long-Term Incentive Plan

The  following  table  describes  performance  units  awarded  to the  executive
officers of Hallwood G.P. for 1997 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                Until Payout         Price-Based Plans(1)

<S>                                    <C>                     <C>                       <C>    
    Anthony J. Gumbiner(2)                 --                     --                       $ --

    William L. Guzzetti                  0.0820                  2002                     23,266

    Russell P. Meduna                    0.0820                  2002                      23,266

    Robert S. Pfeiffer                   0.0560                  2002                      15,889

    Cathleen M. Osborn                   0.0560                  2002                     15,889

</TABLE>

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

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

(2)  In addition,  an award of .4200 units,  with an estimated  future payout of
     $119,165, was made to HSC Financial, with which Mr. Gumbiner is associated.
     The payout period ends in 2002.

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

Under the Incentive  Plan, the Board of Directors of Hallwood G.P. (the "Board")
annually determines the portion of the Partnership's collective interests in the
cash flow from certain  international  projects and from domestic wells drilled,
recompleted  or  enhanced  during  that year (the  "Plan  Year")  which  will be
allocated to  participants  in the plan and the  percentage of the remaining net
present value of estimated  future  production from domestic wells for which the
participants  will  receive  payment in the sixth year of an award.  The portion
allocated to  participants in the plan is referred to as the Plan Cash Flow. The
Board then determines which key employees and consultants may participate in the
plan for the Plan Year and allocates the Plan Cash Flow among the  participants.
Awards  under the plan do not  represent  any actual  ownership  interest in the
wells. Awards are made in the Board's discretion.

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


<PAGE>


The  awards for the 1997 Plan Year were made in January  1997.  No other  awards
were  made in 1997.  For the 1997  Plan  Year,  the  Compensation  Committee  of
Hallwood G.P. determined that the total Plan Cash Flow would be equal to 2.4% of
the cash flow of the domestic wells  completed,  recompleted or enhanced  during
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 1997 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,  to the  extent  of 70% of the  total  award,  and on
individual performance, to the extent of 30% of the total award.

Director Compensation

Each director of Hallwood G.P. who is not an officer of Hallwood G.P. or HCRC or
an  employee of HPI,  is paid an annual fee of $20,000  that is  proportionately
reduced if the director attends fewer than four regularly  scheduled meetings of
the Board during the year. During 1997, 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  1997.  Mr.
Gumbiner  is  Chief  Executive  Officer  and a  director,  and Mr.  Guzzetti  is
President and a director,  of Hallwood Realty. During 1997, 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  $275,000 was paid in 1997 by the Partnership
pursuant to this arrangement. For 1995 and 1996, Mr. Gumbiner had a compensation
agreement with HPI pursuant to which Mr.  Gumbiner was paid $250,000 by HPI, the
Partnership  and their  affiliates.  This  agreement  was  terminated  effective
December 31, 1996. See "Summary Compensation Table" and footnotes for additional
discussion of this arrangement.

The Partnership reimburses Hallwood Group for expenses incurred on behalf of the
Partnership.   In  1997,   the   Partnership   reimbursed   Hallwood  Group  for
approximately $301,000 of expenses.




<PAGE>


ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The  following  table shows  information,  as of February  27,  1998,  about any
individual,  partnership or corporation  that is known to the  Partnership to be
the  beneficial  owner  of more  than 5% of  each  class  of  Units  issued  and
outstanding  and each  executive  officer and director of Hallwood  G.P. and all
executive officers/directors as a group.
<TABLE>
<CAPTION>

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

<S>                                                   <C>                            <C>                    <C>
The Hallwood Group Incorporated                       Class A Units (1)                657,260                6.5
  3710 Rawlins Street, Suite 1500                     Class B Units                    143,773              100.0
  Dallas, Texas 75219                                 Class C Units                     43,816                1.8
Hallwood Consolidated Resources Corporation           Class A Units                  1,948,189               19.5
  4582 S. Ulster Street Parkway, Suite 1700           Class C Units                    129,877                5.3
  Denver, Colorado 80237
Heartland Advisors, Inc                               Class A Units (2)                880,200                8.8
  790 North Milwaukee Street
  Milwaukee, Wisconsin 53202
William Baxter Lee, III                               Class A Units (3)                707,000                7.1
  c/o Glankler Brown, PLLC                            Class C Units (3)                 37,000                1.5
  1700 One Commerce Square
  Memphis, Tennessee
Anthony J. Gumbiner                                   Class A Units                    127,500                  *
William L. Guzzetti                                   Class A Units                     63,850                  *
                                                      Class C Units                          6                  *
Russell P. Meduna                                     Class A Units                     59,500                  *
Cathleen M. Osborn                                    Class A Units                     25,500                  *
Robert S. Pfeiffer                                    Class A Units                     16,803                  *
                                                      Class C Units                         20                  *
Brian M. Troup                                        Class A Units                     85,000                  *
Hans-Peter Holinger
Rex A. Sebastian                                      Class A Units                        400                  *
                                                      Class C Units                         26                  *
Nathan C. Collins
All directors and executive officers as a             Class A Units (4)                378,553                3.7
  group (9 persons)                                   Class C Units                         52                  *

</TABLE>

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

(1)  Includes  143,773  Class B Units  (100%  of the  Class B  Units)  that  are
     convertible into Class A Units one-for one.

(2)  According  to the  Amendment  to  Schedule  13G filed  January  30, 1998 by
     Heartland Advisors,  Inc., the Units to which the schedule relates are held
     in investment  advisory accounts of Heartland  Advisors,  Inc. As a result,
     various  persons  have the right to  receive  or the  power to  direct  the
     receipt  of  dividends  from,  or  the  proceeds  from  the  sale  of,  the
     securities.  No such account is known to have an interest  relating to more
     than 5% of the class.

(4)  According to Schedules 13D dated November 26, 1997.

(5)  Consists of 803 Class A Units and currently exercisable options to purchase
     377,750 Class A Units.


See  Item  8 -  Financial  Statements  and  Supplementary  Data  (Note  9 to the
Financial Statements) for a description of HEP's Unit Option Plan.


ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

See  Item 8 -  Financial  Statements  and  Supplementary  Data  (Note  10 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.
    (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
   (10)  10.12  - Amendment  to the Third  Amended and  Restated  Agreement of
                  Limited  Partnership  of HEP  Operating Partners, L.P.
   (10)  10.13-   Second  Amendment  to the Second  Amended  and  Restated
                  Agreement  of Limited  Partnership  of EDP Operating, Ltd.
   *(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
    (7)  21     - Subsidiaries of Registrant
         23.1 - Consent of  Deloitte  & Touche LLP
         23.2 - Consent of  Deloitte & Touche LLP
    --------------

   (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.


<PAGE>


       (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  Form10-Q  for the quarter
              ended September 30, 1997.


        *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:  February 27, 1998                             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.

<TABLE>
<CAPTION>


                 Signature                                 Capacity                              Date





<S>                                          <C>                                          <C> 
/s/Anthony J. Gumbiner                        Chairman of the Board and                   February 27, 1998
Anthony J. Gumbiner                           Director (Chief Executive Officer)




/s/Brian M. Troup                             Director                                    February 27, 1998
Brian M. Troup




/s/Hans-Peter Holinger                        Director                                    February 27, 1998
Hans-Peter Holinger




/s/Rex A. Sebastian                           Director                                    February 27, 1998
Rex A. Sebastian




/s/Nathan C. Collins                          Director                                    February 27, 1998
Nathan C. Collins




/s/Robert S. Pfeiffer                         Principal Accounting Officer                February 27, 1998
Robert S. Pfeiffer

</TABLE>