SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 10-KSB

                  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1996


                         Commission file number 0-19767

                       THE HOME-STAKE ROYALTY CORPORATION
                 (Name of small business issuer in its charter)

               Oklahoma                                     73-0288040
      (State or other jurisdiction of                    (I.R.S. Employer
       incorporation or organization)                   Identification No.)

      15 East 5th. Street, Suite 2800
          Tulsa, Oklahoma                                     74103
  (Address of principal executive offices)                  (Zip Code)

                    Issuer's telephone number: (918) 583-0178

           Securities registered under Section 12(b) of the Act: None

              Securities registered under Section 12(g) of the Act:

                    Common Stock, par value $40.00 per share

        Check whether the issuer (1) has filed all reports  required to be filed
by  Section  13 or 15(d) of the  Exchange  Act during the past 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

        Check if  disclosure  of  delinquent  filers in  response to Item 405 of
Regulation  S-B is not  contained  in  this  form,  and no  disclosure  will  be
contained,  to the best of the  Registrant's  knowledge,  in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. |_|

        State issuer's revenues for its most recent fiscal year:   $8,213,464

        As of March 26, 1997,  69,808  shares of the  Registrant's  Common Stock
were  outstanding.  The  Registrant is unable to determine the aggregate  market
value of the Common Stock held by  non-affiliates  as there are no published bid
and asked prices on transactions in the Common Stock.

                       DOCUMENTS INCORPORATED BY REFERENCE

        Portions of the  Registrant's  Proxy Statement for the Annual Meeting of
Stockholders  to be held May 19, 1997, are  incorporated  by reference into Part
III of this Form 10-KSB.

        Transitional Small Business Disclosure Format (Check one) Yes    No |X|





<PAGE>



                       THE HOME-STAKE ROYALTY CORPORATION

                                   FORM 10-KSB
                          YEAR ENDED DECEMBER 31, 1996

                                TABLE OF CONTENTS

                                                                          Page
                                     PART I

Item 1.    Description of Business.........................................  1

Item 2.    Description of Property.........................................  6

Item 3.    Legal Proceedings............................................... 12

Item 4.    Submission of Matters to a Vote of Security Holders............. 12


                               PART II

Item 5.    Market for Common Equity and Related Stockholder Matters........ 13

Item 6.    Management's Discussion and Analysis............................ 13

Item 7.    Financial Statements............................................ 16

Item 8.    Changes in and Disagreements with Accountants
           on Accounting and Financial Disclosure.......................... 16

                              PART III

Item 9.    Directors, Executive Officers and Compliance with Section 16(a)
           of the Exchange Act............................................. 16

Item 10.   Executive Compensation.......................................... 17

Item 11.   Security Ownership of Certain Beneficial Owners and Management.. 17

Item 12.   Certain Relationships and Related Transactions.................. 17

                               PART IV

Item 13.   Exhibits and Reports on Form 8-K................................ 17

Signatures       ...........................................................19

Index to Consolidated Financial Statements................................. F-1


                                       -i-

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                                     PART I


Item 1., Description of Business, and Item 2., Description of Property,  include
certain  statements  which are not  historical  fact,  but are "forward  looking
statements". These forward looking statements are based on current expectations,
estimates,  assumptions and beliefs of management;  and words such as "expects",
"believes",  "anticipates",  "intends",  "plans"  and  similar  expressions  are
intended to identify such forward  looking  statements.  The Home-Stake  Royalty
Corporation  (the  "Company")  does not  undertake to update,  revise or correct
forward  looking  information.  Readers are cautioned that such forward  looking
statements should be read in connection with the Company's disclosures under the
heading "Forward Looking Statements", included on page 16 hereof.

ITEM 1. DESCRIPTION OF BUSINESS

General

     The  Company  is  actively   engaged  in  the   acquisition,   exploration,
development and production of oil and gas properties.  Its principal  geographic
operating areas lie within the states of Oklahoma,  Montana, Wyoming,  Louisiana
and Texas.

     The Company was  incorporated  in the State of Oklahoma in 1929.  Since its
incorporation,  the Company has been under common management with The Home-Stake
Oil & Gas  Company,  an  Oklahoma  corporation  formed  in  1917  ("HSOG").  The
Company's principal business activity from the date of its incorporation through
the  early  1950's  was the  acquisition  and  leasing  of oil  and gas  mineral
interests.  Accordingly,  the Company's revenues were primarily from its royalty
interests in oil and gas  production  from the mineral  interests in  properties
leased to  others.  Beginning  in the  1950's,  the  Company  began to  actively
participate as a working  interest  partner  primarily in wells being drilled by
other industry  partners.  The Company also  originated and  participated in the
drilling of a few of its own prospects and discovered  several  significant  oil
fields in south central Kansas.

     Since the 1950's,  the  Company has  participated  in the  acquisition  and
drilling of oil and gas  properties  jointly  with HSOG.  Since that time,  both
companies have operated in most respects as a single entity  (collectively,  the
Company  and HSOG  are  sometimes  hereinafter  referred  to as "The  Home-Stake
Companies"  or  the  "Companies").  The  Companies  jointly  participate  in the
acquisition  of  mineral  and  leasehold   interests  and  in  exploration   and
development  activities  performed  on jointly  owned  properties.  Each company
generally  owns an equal  interest in the oil and gas  properties,  however such
interests  may vary.  Only the Company,  however,  serves as operator of certain
producing  properties owned by The Home-Stake  Companies.  The Company currently
operates 63 producing wells.

     In November 1995, the Boards of Directors of The Home-Stake Companies voted
to  change  the  participation  arrangement  between  the  Companies  such  that
effective January 1, 1996, the Company participated with a 60% interest in joint
ventures (drilling,  acquisitions and/or other investments)  between the Company
and HSOG, with HSOG  participating  in such ventures with a 40% interest.  Joint
general and administrative  expenses continue to be shared on a 50-50 basis. The
Boards felt this change was in the best  interests of each  company,  based on a
review of their respective financial conditions.  This participation arrangement
is reviewed by the Boards on an annual basis and future  changes will be made as
circumstances, in the judgment of the Boards, require.

     In the  mid-1970's  the Company  revised its business  strategy to pursue a
program  to  increase  its  revenues  generated  from the  ownership  of working
interests  in oil and gas  properties  relative to its revenues  generated  from
royalty  interests  (resulting  from the  ownership  and  leasing of oil and gas
mineral  interests).  The Company increased its relative  investment in drilling
ventures  developed and sold by other  industry  partners and in the oil and gas
properties that it acquired. In 1977, the Company received  approximately 75% of
its revenues from royalty interests,  whereas, in 1996, approximately 27% of its
revenues were from royalty interests.



                                       -1-

<PAGE>



     At  December  31,  1996,  the  Company  had  estimated  proved  reserves of
8,835,929 Mcf of natural gas and 2,432,711  barrels of oil. Natural gas reserves
constituted  approximately  38% of  the  Company's  reserves  based  on an  "oil
equivalent"  basis  (converting  each six Mcf of natural gas to a barrel of oil,
representing the estimated relative energy content of oil and natural gas).

Subsidiary and Partnership

     Alden Gas  Gathering  Company,  an Oklahoma  corporation  and wholly  owned
subsidiary  of the  Company,  was formed in 1989 for the purpose of owning a 41%
general  partnership  interest in Alden Pipeline  Company,  an Oklahoma  general
partnership  ("Alden").  Alden Gas Gathering Company and H-S Gas System, Inc., a
wholly owned subsidiary of HSOG, serve as general partners of Alden.  Alden owns
and operates a small  gathering  system in Caddo County,  Oklahoma.  This system
collects and transports gas from wells operated by the Company to a trunkline of
a major pipeline. Alden Gas Gathering Company invested approximately $100,000 in
this  partnership  and is receiving its  proportionate  share of the profits and
losses,  which  represented  a loss of $9,814 in 1996.  In  addition,  Alden Gas
Gathering Company and H-S Gas System, Inc. each receive a monthly administrative
overhead fee of $750 in their  capacity as general  partners of Alden.  In March
1997, the Company and HSOG sold their  interests in Alden  Pipeline  Company and
the related producing properties at a gain of approximately $100,000.

     The Company and HSOG also serve as general  partners of H-S Royalty,  Ltd.,
an  Oklahoma  limited  partnership  (the  "Partnership")  formed  in  1982.  The
Partnership was formed by the Companies for the purpose of distributing to their
stockholders  a  3/16th  royalty  interest  in  certain  jointly  owned  mineral
interests in properties, which were nonproducing at the time of the formation of
the Partnership,  located in ten states.  Management of The Home-Stake Companies
distributed  the  royalty  interests  to allow their  stockholders  to realize a
portion  of the  direct  economic  benefits  that  result  from  the  commercial
production  and  sale of oil and gas,  as well as the  maximization  of  certain
income  tax  benefits  attributable  to oil and  gas  producing  activities.  In
connection with the  administration  of the Partnership,  the Company receives a
monthly administrative management fee of $250.

Competition

     The business of acquiring and  developing  desirable oil and gas properties
is highly competitive.  In seeking to obtain desirable producing properties, new
leases and exploration prospects,  the Company faces competition from both major
and independent oil and gas companies,  as well as from numerous individuals and
income and drilling programs. Many of these competitors have financial and other
resources substantially in excess of those available to the Company.

     There is also extensive competition in locating markets for gas produced by
the Company.  Increases in worldwide energy production  capability and decreases
in energy  consumption  as a result of  conservation  efforts have brought about
substantial  surpluses in energy  supplies in recent years.  This, in turn,  has
resulted in substantial  competition for markets historically served by domestic
natural gas sources both with alternate sources of energy, such as residual fuel
oil, and among domestic gas suppliers.  As a result,  there have been reductions
in oil prices, widespread curtailment of gas productions and delays in producing
and marketing  gas after it is  discovered.  Changes in  government  regulations
relating to the  production,  transportation  and  marketing of natural gas have
also resulted in significant changes in the historical marketing patterns of the
industry.  Generally,  these  changes have resulted in the  abandonment  by many
pipelines  of  long-term   contracts  for  the  purchase  of  natural  gas,  the
development  by gas producers of their own marketing  programs to take advantage
of new regulations  requiring pipelines to transport gas for regulated fees, and
an increasing  tendency to rely on  short-term  sales  contracts  priced at spot
market prices.


     In light of these developments, many producers, including the Company, have
accepted oil prices that may differ from area  "posted  prices" in order to sell
their production.  Also, gas prices,  which were once effectively  determined by
government   regulations,   are  now  influenced   largely  by  the  effects  of
competition.  Competitors in this market include other producers,  gas pipelines
and their affiliated marketing companies,  independent marketers,  and providers
of alternate energy supplies, such as residual fuel oil.


                                       -2-

<PAGE>



Marketing

     The  Company's  gas  production  from  properties  in which it owns working
interests  is sold  primarily  on the spot market with a variety of  purchasers,
including   intrastate  and  interstate  pipeline  companies,   their  marketing
affiliates,  independent  marketing  companies and other  companies who have the
ability to move gas under firm  transportation  agreements.  Gas  produced  from
properties  in which the Company owns royalty  interests is marketed and sold by
owners of the leasehold interests in such properties.

     Substantially  all of the Company's crude oil and condensate  production is
sold at  posted  prices  under  short-term  contracts,  as is  customary  in the
industry.

Seasonality

     The  results  of   operations  of  the  Company  are  subject  to  seasonal
fluctuations  in the  price  for  natural  gas.  Natural  gas  prices  have been
generally  higher  in the  fourth  and  first  quarters.  Due to these  seasonal
fluctuations,  results of operations for individual quarterly periods may not be
indicative of results which may be realized on an annual basis.

Regulation

     General

     The oil and gas industry is  extensively  regulated  by federal,  state and
local  authorities.  Legislation  affecting  the oil and gas  industry  is under
constant review for amendment or expansion.  Numerous  departments and agencies,
both federal and state, have issued rules and regulations binding on the oil and
gas  industry  and its  individual  members,  some of  which  carry  substantial
penalties for the failure to comply.  The  regulatory  burden on the oil and gas
industry  increases its cost of doing  business and,  consequently,  affects its
profitability.  Inasmuch as such laws and regulations are frequently  amended or
reinterpreted,  the  Company is unable to predict  the future  cost or impact of
complying with such regulations.

     Exploration and Production

     Exploration and production operations of the Company are subject to various
types of regulation  at the federal,  state and local  levels.  Such  regulation
includes  requiring  permits  for the  drilling  of wells,  maintaining  bonding
requirements in order to drill or operate wells,  and regulating the location of
wells,  the method of drilling and casing wells, the surface use and restoration
of  properties  upon which wells are drilled and the plugging and  abandoning of
wells.  The  Company's  operations  are also  subject  to  various  conservation
matters.  These include the regulation of the size of drilling and spacing units
or  proration  units  and the  density  of wells  which may be  drilled  and the
unitization or pooling of oil and gas  properties.  In this regard,  some states
allow the forced  pooling or  integration  of tracts to  facilitate  exploration
while other states rely on voluntary  pooling of lands and leases.  In addition,
state  conservation  laws establish maximum rates of production from oil and gas
wells,  generally  prohibit  the  venting or  flaring of gas and impose  certain
requirements  regarding  the  ratability  of  production.  The  effect  of these
regulations  is to limit the amounts of oil and gas the Company can produce from
their  wells,  and to limit the  number of wells or the  locations  at which the
Company can drill.

     Oklahoma and Texas have adopted  limits on gas  production  that attempt to
match production with market demand. In March 1992, Oklahoma enacted a law which
places statewide limits on gas production.  The Oklahoma Corporation  Commission
sets production  levels  quarterly.  The production of natural gas from a single
well is limited to the greater of a specified Mcf per day or a percentage of the
total daily  production  capacity of the well. In April 1992, the Texas Railroad
Commission ("TRC")  unanimously  approved a new proration system that eliminated
monthly purchaser  nominations as the starting point for determining  production
allowable.  Under  the  new  Texas  regulations,  the  TRC  utilizes  historical
production  data for each well during the same month from the previous  year and
the  operator's  forecast  for  demand  for the month to arrive at a  production
allowable.  The Company cannot  predict  whether other states will adopt similar
regulations  or  legislation  with  respect to  governing  gas  production.  The

                                       -3-

<PAGE>



possible  effect of such  regulations  and  legislation  may be to decrease  the
allowable  daily   production  and  revenues  from  gas  properties,   including
properties  that  produce  both  oil and  gas.  It is also  possible  that  such
regulations  and  legislation may result in a decrease in gas production in such
states,  which could exert upward  pressure on the price of gas,  although there
can be no  assurance  that  any  such  increase  will  occur.  However,  if such
regulations or restrictions  do result in increased  prices of natural gas, they
could face  challenges  in the courts  and there can be no  assurance  as to the
outcome of any such  challenge.  It is also  possible  that federal  legislation
could be enacted to override the effects of such state provisions.

     Various  federal,  state  and  local  laws  and  regulations  covering  the
discharge  of  materials  into the  environment,  or  otherwise  relating to the
protection of the environment may affect the Company's operations and costs as a
result of their effect on exploration,  development  and production  operations.
Violation  of  environmental  legislation  and  regulations  may  result  in the
imposition   of  fines  or  civil  or   criminal   penalties   and,  in  certain
circumstances,  the entry of an order for the removal, remediation and abatement
of the conditions and suspension of the activities giving rise to the violation.
The  Company is also  subject to laws and  regulations  concerning  occupational
safety and health.  It is not  anticipated  that the Company will be required in
the near future to expend  amounts  that are  material in the  aggregate  to the
Company's overall  operations by reason of environmental or occupational  safety
and health laws and  regulations,  but inasmuch as such laws and regulations are
frequently  changed,  the  Company is unable to  predict  the  ultimate  cost of
compliance.

     Certain of the  Company's  oil and gas leases  are  granted by the  federal
government and  administered  by various federal  agencies.  Such leases require
compliance with detailed  federal  regulations and orders which regulate,  among
other  matters,  drilling  and  operations  on these leases and  calculation  of
royalty  payments to the federal  government.  The Mineral  Lands Leasing Act of
1920 places  limitations on the number of acres under federal leases that may be
owned in any one state.  While  subject to this law, the Company does not have a
substantial federal lease acreage position in any state or in the aggregate. The
Mineral  Lands Leasing Act of 1920 and related  regulations  also may restrict a
corporation  from the holding of federal  onshore oil and gas leases if stock of
such corporation is owned by citizens of foreign  countries which are not deemed
reciprocal under such Act.  Reciprocity  depends,  in large part, on whether the
laws of the foreign  jurisdiction  discriminate against a United States person's
ownership of rights to minerals in such jurisdiction.  The purchase of shares in
the Company by citizens of foreign countries who are not deemed to be reciprocal
under  such Act could  have an  impact on the  Company's  ownership  of  federal
leases.

     Natural Gas Sales and Transportation

     Federal legislation and regulatory controls have historically  affected the
price of the gas produced by the Company and the manner in which such production
is  marketed.  Historically,  the  transportation  and sale for resale of gas in
interstate  commerce has been regulated  pursuant to the Natural Gas Act of 1938
(the  "NGA") and the  Natural  Gas Policy Act of 1978 (the  "NGPA")  and Federal
Energy Regulatory Commission ("FERC") regulations promulgated thereunder.  Since
1978,  maximum  selling  prices of certain  categories  of gas,  whether sold in
interstate or intrastate commerce, have been regulated pursuant to the NGPA. The
NGPA  established   various   categories  of  gas  and  provided  for  graduated
deregulation of price controls of several categories of gas and the deregulation
of sales of certain categories of gas. All price deregulation contemplated under
the NGPA has already  taken place.  On July 26,  1989,  the Natural Gas Wellhead
Decontrol  Act of 1989 (the  "Decontrol  Act") was enacted.  The  Decontrol  Act
amended  the NGPA to  remove,  as of July 27,  1989,  both  price and  non-price
controls  from gas not  subject to a contract  in effect on July 26,  1989.  Gas
under  contract  on July  26,  1989,  was  decontrolled  on the  earlier  of the
termination  of the contract or January 1, 1993.  Gas from wells  spudded  after
July 26,  1989,  was  decontrolled  on May 15,  1991,  even if those  wells were
covered by an existing contract.

     In  December  1992,  the FERC  issued  Order  No.  547,  which is a blanket
certificate of public convenience and necessity pursuant to Section 7 of the NGA
and which authorizes any company which is not an interstate natural gas pipeline
or an  affiliate  thereof  to make  sales  for  resale  at  negotiated  rates in
interstate  commerce  of any  category  of gas that is subject to the FERC's NGA
jurisdiction.  The blanket  certificates  were effective January 7, 1993, and do
not require any further  application.  There are certain requirements which must
be met before an affiliated  marketer of an interstate pipeline can avail itself
of this certificate.


                                       -4-

<PAGE>



     Due to the deregulation provisions of the NGPA, the Decontrol Act and Order
No. 547, the price of virtually  all gas  produced by producers  not  affiliated
with interstate pipelines has been deregulated by FERC. As a result, most of the
Company's' gas production is no longer  subject to price  regulation.  Gas which
has  been  removed  from  price   regulation  is  subject  only  to  that  price
contractually agreed upon between the producer and purchaser.  Market determined
prices for  deregulated  natural gas fluctuate in response to market  pressures.
Under recent market conditions,  deregulated gas prices under new contracts tend
to be lower than most  regulated  price  ceilings  previously  prescribed by the
NGPA. As a result of the  deregulation of a greater portion of the United States
gas  market  and  an  increased   availability  of  natural  gas  transportation
(discussed below), a competitive trading market for gas has developed.

     In February  1988,  the FERC issued Order No. 490,  which  promulgated  new
abandonment  regulations for expired,  canceled or modified contracts  involving
the sale of certain gas committed or dedicated to interstate  commerce  prior to
the enactment of the NGPA. The new rules largely eliminate delays and regulatory
burdens   associated  with  securing   approval  to  abandon  gas  service  upon
termination  or expiration of a contract for the sale of such gas. The new rules
also   significantly   facilitate  certain  pipelines'  ability  to  discontinue
purchasing  such gas under terms  unfavorable  to the pipeline in  situations in
which the contract has expired or terminated,  but abandonment  authorization is
required to terminate the service.  Order No. 490 is currently being  challenged
in the courts.

     Commencing in late 1985, the FERC issued a series of orders (Order No. 436,
Order No. 500 and related orders),  which  promulgated  regulations  designed to
create a more  competitive,  less  regulated  market for natural gas.  These and
subsequent  regulations have significantly  altered the marketing and pricing of
gas. Among other things, these regulations (a) require interstate pipelines that
elect to transport gas for others under  self-implementing  authority to provide
transportation  services to all shippers on a non-discriminatory  basis, and (b)
permit each existing firm sales customer of any such pipeline to modify, over at
least a five-year period,  its existing purchase  obligations.  Although the new
regulations  do not directly  regulate gas  producers  such as the Company,  the
effect of these  regulations  has been to enhance  the ability of  producers  to
market their gas directly to end users and local distribution companies.

     In April 1992 (and  clarified  in August  1992 and  finalized  in  November
1992), the FERC issued Order 636, a complex regulation which is expected to have
a major impact on natural gas  pipeline  operations,  services and rates.  Among
other things,  Order 636 requires each interstate pipeline company to "unbundle"
its traditional  wholesale services and create and make available on an open and
nondiscriminatory   basis  numerous  constituent  services  (such  as  gathering
services, storage services, firm and interruptible  transportation services, and
stand-by sales services) and to adopt a new rate making methodology to determine
appropriate rates for those services.  To the extent the pipeline company or its
sales  affiliate  makes gas sales as a merchant in the future,  it will do so in
direct  competition  with all  other  sellers  pursuant  to  private  contracts;
however,  pipeline  companies are not required to remain "merchants" of gas, and
many of the interstate pipeline companies have or will become transporters only.
Each pipeline company had to develop the specific terms of service in individual
proceedings.  The new rules are subject to pending court  challenges by numerous
parties.  In addition,  many of the individual  pipeline  restructurings are the
subject of pending appeals, either before the FERC or in the courts.

     As noted,  Order 636 is still in the judicial  review stage. On October 29,
1996,  the United  States Court of Appeals for the District of Columbia  Circuit
denied  petitions for  rehearing of its earlier  decision,  United  Distribution
Companies  v. FERC,  88 F.3d  1105,  1191 (D.C.  Cir.  1996),  in which the D.C.
Circuit  upheld most of Order 636.  However,  the Court remanded to the FERC for
further explanation the provisions  pertaining to (1) restriction of entitlement
to receive no-service to those customers who received bundled firm-sales service
on  May   18,   1992;   (2)   the   twenty-year,   term-matching   cap  for  the
right-of-first-refusal mechanism; (3) two aspects of the straight fixed variable
rate  design  mitigation  measures;  and (4) why,  in light of Order 500 and the
general  cost-spreading  principles of Order 636, pipelines can pass through all
their gas supply  realignment  ("GSR")  transition  costs to  customers  and why
interruptible transportation customers should bear 10% of GSR costs.

     The  issuance  of Order 636 and its future  interpretation,  as well as the
future  interpretation and application by FERC of all of the above rules and its
broad authority, or of the state and local regulations by the relevant agencies,

                                       -5-

<PAGE>



could  affect  the  terms  and  availability  of  transportation   services  for
transportation  of natural gas to  customers  and the prices at which gas can be
sold.  For instance,  as a result of Order 636, a number of interstate  pipeline
companies have (i) "spun-down" their gathering  systems from regulated  pipeline
transportation  companies to unregulated  affiliates,  (ii) "spun-off" gathering
systems to non-related  entities,  and/or (iii)  "refunctionalized"  portions of
their pipeline  facilities  from  transmission  to gathering.  In a May 27, 1994
order and a December 2, 1994 rehearing order,  FERC ruled that it generally does
not have  jurisdiction  over  gathering  facilities  absent abuse  involving the
pipeline-affiliate relationship.  However, FERC directed pipelines spinning down
or off their  gathering  systems to include  certain  Order No. 497 standards of
conduct in their tariffs and to enter into continuity of service agreements with
existing  users or to  execute a  "default  contract"  with users with whom they
cannot reach agreement,  with the default contract to contain a minimum two-year
term,  use the  pipeline  gatherer's  then  current  rate  (with an  appropriate
escalator clause) for existing customers for similar service,  and contain terms
and conditions  consistent  with those  applicable to the  pipeline's  gathering
service. However, in 1996 the United States Court of Appeals for the District of
Columbia upheld the FERC's allowing the spinning down of gathering facilities to
a non-regulated  affiliate,  but remanded the FERC's default contract mechanism.
On October 31, 1996, four producers,  Amoco Energy Trading Corp.  (together with
its parent,  Amoco Production Co.),  Anadarko  Production Corp., Conoco Inc. and
Marathon Oil Co.,  petitioned  the Supreme  Court of the United States to review
the D.C.  Circuit's  upholding  the FERC's  determination  not to  regulate  the
gathering  systems spun down to affiliates  except in circumstances of affiliate
abuse.  Consequently,  the  Company  cannot  reliably  predict  at this time how
regulation will ultimately impact the Company's natural gas operations.

     Operational Hazards and Insurance

     The  operations  of the Company  are  subject to all risks  inherent in the
exploration for, and development and production of, oil and gas,  including such
natural hazards as blowouts,  cratering and fires,  which could result in damage
or injury  to, or  destruction  of,  drilling  rigs and  equipment,  formations,
producing facilities or other property, or could result in personal injury, loss
of life or pollution of the environment.  Such event could result in substantial
cost to the  Company  which  could have an  adverse  effect  upon the  financial
condition  of the  Company to the extent it is not fully  insured  against  such
risk.  The  Company  carries  insurance  against  certain of these risks but, in
accordance with standard industry practice,  is not fully insured for all risks,
either  because such insurance is unavailable or because it elects not to obtain
insurance coverage because of cost.  Although such operational risks and hazards
may to some extent be minimized,  no combination  of  experience,  knowledge and
scientific evaluation can eliminate the risk of investment or assure a profit to
any company engaged in oil and gas operations.

Employees

     At December  31,  1996,  the  Company  employed  15 persons  (currently  18
persons) whose functions are associated with management,  operations and mineral
management,   engineering,   geology,  land  and  gas  contract  administration,
accounting and financial planning, and administration and data processing.  Each
employee  holds an  identical  position  with  HSOG and is  considered  to spend
one-half of his or her time on the Company's business.  Accordingly, the Company
pays  one-half  of the  compensation  to its  employees  and HSOG pays the other
one-half.  The  Company  considers  its  relations  with  its  employees  to  be
excellent.

ITEM 2.  DESCRIPTION OF PROPERTY

General

     The Company owns interests in 1,437  producing  properties,  including both
working  interests  and royalty  interests,  located in 16 states.  (For further
details  regarding these  properties see "Producing  Wells"  included  elsewhere
herein.)  The  Company is engaged  in  leasing  of its  minerals  as well as the
exploration,  production and sale of natural gas,  condensate and crude oil from
its properties.

     The Company has an extensive  ownership of nonproducing  perpetual minerals
located in 16 states,  including  North  Dakota,  Oklahoma,  Michigan,  Montana,
Mississippi and Texas. Such ownership comprises 3,203 properties covering 52,886
net  acres.  The  Company  may  from  time-to-time  participate  in  exploration
activities on certain of these properties,  but generally leases them to others,

                                       -6-

<PAGE>



retaining a royalty  interest in whatever  production may be derived  therefrom,
thereby  eliminating  the risk in the  exploration  of such  properties.  At the
present time, there are  approximately  56 properties  leased to others for such
exploration comprising 1,557 net acres.

     In  addition,  the Company  owns a leasehold  interest in 113  nonproducing
properties  comprising  3,198 net acres.  These  properties  have varying  lease
terms, with most expiring in the next five years. These leasehold  interests are
located in eleven states, including Oklahoma and Montana.

1996 Acquisitions

     During  1996 the  Company  participated  with  HSOG in one  acquisition  of
producing  properties.  This group of 23 properties was acquired in November and
included properties in Wheeler County, Texas; Stephens County, Oklahoma;  Beaver
County,  Oklahoma; and Union Parish,  Louisiana. The Company participated with a
60%  interest  in this  acquisition,  at a cost of  $324,000  and  added  proved
developed  reserves of 479,400 Mcf (net) of natural gas and 16,000 barrels (net)
of oil.

Current Activities

     The Company's  exploration and development  activities  generally have been
located in the states of Oklahoma (Anadarko Basin),  Montana and Texas. In 1996,
the majority of the Company's  activities were located in Gaines County,  Texas,
as well as Comanche and Caddo Counties,  Oklahoma. Most recent drilling has been
developmental  in  nature  (85% in 1996  and 88% in  1995)  on both  oil and gas
properties.  In 1996,  there were 5 oil wells and 14 gas wells drilled;  in 1995
there were 3 oil wells and 15 gas wells drilled.

     During  1997,  the  Company's  drilling  activities  will  continue  to  be
primarily  developmental  in nature.  The  Company  is  presently  committed  to
participate  in the drilling (or  completion) of 14 (1.2 net) wells in 1997. The
Company expects to operate three (0.45 net) of these wells. In 1997, the Company
has  budgeted  $1.7  million for  drilling  activities,  of which  approximately
$454,000 has been committed.  In 1997 the Company contracted with two consulting
geologists  for the right of first refusal on  developmental  prospects they are
developing in the Permian  Basin of Texas.  The primary area of focus during the
next 12 to 18 months will be  developmental  drilling on the Company's  Oklahoma
acreage and in the Permian  Basin of Texas.  In addition,  the Company  plans to
continue to pursue  exploratory oil and gas prospects in the Anadarko and Arkoma
Basins in Oklahoma.

     The Company and HSOG remain active in the property  acquisition  market. In
1996, The Home-Stake Companies reviewed 68 property sales packages and submitted
bids on four of these packages, containing eight groups of properties. They were
successful in acquiring  one group of  properties.  Through March 15, 1997,  The
Home-Stake Companies have reviewed 12 sales packages.

     During 1995 the Company acquired  approximately  220 net acres of leases in
the Lodgepole "play" in North Dakota at a cost of $85,000. The Lodgepole area is
generating  a great  deal of  interest  in the  oil and gas  industry  and it is
expected that new drilling will  commence in this area. In February,  1996,  the
Company  executed  permits to allow 3-D seismic work on certain of these leases.
There are no present plans by the Company to initiate  exploration  in this area
in the near future;  however,  it is the Company's intention to participate with
its leased acreage in wells proposed by others.

Drilling Activity

     During the periods  indicated,  the Company  drilled or participated in the
drilling of the following exploratory and development wells:


                                       -7-

<PAGE>




                                    Years ended December 31,
                             1996             1995              1994
=============================================================================
                       Gross      Net    Gross      Net    Gross     Net
Exploratory:
 Productive.........      1       .17       0       .00       0      .00
 Nonproductive......      2       .29       2       .44       2      .09
                         --      ----      --      ----      --     ----
   Total............      3       .46       2       .44       2      .09
                         ==      ====      ==      ====      ==     ====
Development:
 Productive.........     13       .26      13       .41      10     1.21
 Nonproductive......      3       .48       3       .19       1      .25
                        ---      ----      --      ----      --     ----
   Total............     16       .74      16       .60      11     1.46
                         ==      ====      ==       ===      ==     ====
Total:
 Productive.........     14       .43      13       .41      10     1.21
 Nonproductive......      5       .77       5       .63       3      .34
                        ---    ------      --      ----      --     ----
    Total...........     19      1.20      18      1.04      13     1.55
                         ==     =====      ==      ====      ==     ====
=============================================================================


     The above well information  excludes wells in which the Company owns only a
royalty or mineral interest.

     At December 31, 1996, the Company was  participating in the drilling of six
(.33 net) wells.  Through the date of this report, four (.19 net) of these wells
have been completed, resulting in one dry hole and three gas wells. In addition,
the  Company  participated  in one other  gas well  (.18  net) that was  spudded
subsequent to year-end.

Operating Activities

     The Company operates 63 producing wells and 10 service wells located in ten
separate fields, which includes two waterfloods consisting of 20 producing wells
and six service  wells.  In  addition,  the Company has a  non-operator  working
interest ownership in approximately 260 other properties.

     The Company  operates  wells in two fields in Dawson County,  Montana.  The
operations  in the  Glendive  Field  consist  of 15  producing  wells  and  four
saltwater  disposal wells. The Gas City Field is unitized for secondary recovery
operations and consists of nine producing wells and three water injection wells.
Production is primarily  from the Red River  formation of Ordovician age in both
of these fields.

     The N.E.  Alden  Field in Caddo  County,  Oklahoma  produces  from  several
different reservoirs.  The Alden Bromide Unit is unitized for secondary recovery
operations  in the Bromide  formation and consists of four  producing  wells and
three water injection wells.  There are seven  non-unitized  wells which produce
from four other  formations  from  Mississippian  to Ordovician in age. In March
1997,  the  Company  and HSOG sold  their  interests  in this field at a gain of
approximately $100,000, each company.

     Operations  in the Golden  Trend  Field in Grady and  McClain  counties  in
Oklahoma  consist  of  16  producing  wells  completed  in  four  formations  of
Pennsylvanian and Ordovician age rock.


                                       -8-

<PAGE>



     Northwestern  Oklahoma  operations  consist of five producing  wells in the
Vici Field in Ellis County. Production is from Pennsylvanian age rock.

     The Company's operations in the Anadarko Basin of Eastern Oklahoma consists
of five producing gas wells located in the Hartshorne  South and Kinta Fields in
Latimer County and the Ti North and Ashland Fields in Pittsburg County.

     The  Company's  other  producing  field is the West  Cement  Field in Caddo
County,  Oklahoma.  At present,  there is one  producing  well  completed in the
Medrano formation of Pennsylvania age rock.

     The Company also  operates one well in the Champmon  Strawn Field in Gaines
County, Texas.

Producing Wells

     The  following  table  sets  forth  certain  information  relating  to  the
Company's producing  properties.  Because the Company owns the mineral interests
in numerous producing  properties,  it does not have current  information on the
numbers  of wells  drilled by the owners of the  leasehold  interests  for these
properties.  Accordingly,  the Company keeps track of its royalty interests on a
property-by-property  rather than a well-by-well  basis, and the following table
sets forth the number of properties  upon which there are one or more  producing
wells. Net wells refers to the total number of wells in which the Company has an
interest, multiplied by the Company's working interest percentage in the wells.


                      Producing Wells as of December 31, 1996
==============================================================================
                                                            Gross        Net
                                                            -----       -----
Working interests -           Oil...................          122         18
                              Gas...................          190         10
Royalty interests -           Oil...................          676         (1)
                              Gas...................          449         (1)

==============================================================================

     (1) The term "net wells" is not applicable to a royalty  interest since the
         Company has no working interest in the applicable well.



                                       -9-

<PAGE>



Acreage

         As previously  noted,  the Company owns an interest in 1,437  producing
properties,  including royalty interests in 1,125 properties  (comprising 14,963
net acres) and working interests in 312 properties (comprising 8,202 net acres).
The following table sets forth the Company's gross and net oil and gas leasehold
acreage as of December 31, 1996.


                           Acreage as of December 31, 1996
==============================================================================
                                                         Gross            Net
Developed Acreage:
          Leasehold..............................       73,350          7,476
          Mineral................................      285,800         15,689
Undeveloped Acreage:
          Leasehold..............................       23,924          3,198
          Mineral................................      632,613         52,886
                                                    ----------     ----------
Total Acreage                                        1,015,687         79,249
                                                    ==========     ==========

==============================================================================

Proved Reserves

     The  following  table  reflects the proved  reserves  and proved  developed
producing  reserves,  future net  revenues  and the present  value of future net
revenues  from such reserves of the Company at December 31, 1996 as estimated by
the Company.  The quantities of the Company's proved reserves of oil and natural
gas presented below,  representing  developed and undeveloped reserves,  include
only those amounts which the Company reasonably expects to recover in the future
from  known  oil  and gas  reservoirs  under  existing  economic  and  operating
conditions.  Proved developed producing reserves are limited to those quantities
which are  recoverable  commercially  from existing  wells at current prices and
costs,  under  existing  regulatory  practices  and  with  existing  technology.
Accordingly,   any  changes  in  prices,   operating  and  developmental  costs,
regulations,  technology  or  other  factors  could  significantly  increase  or
decrease  estimates of the Company's proved developed  producing  reserves.  The
Company's  proved  undeveloped  reserves include only those quantities which the
Company  reasonably  expects to recover  from the drilling of new wells based on
geological  evidence from  directly  offsetting  wells.  The risks of recovering
these reserves are higher from both geological and mechanical  perspectives than
the risks of  recovering  developed  reserves.  The  estimates of the  Company's
proved reserves do not include proved undeveloped  reserves  attributable to the
Company's  royalty  interests (this information is not available to the Company)
or outside operated working interests (quantities are not considered material to
the  Company's  proved  reserves).  Furthermore,  the reserve  estimates  do not
include reserves whose estimates of  recoverability  are less precise,  commonly
referred to as "probable" or  "possible"  reserves.  The Company has no reserves
outside the continental United States.


                                      -10-
<PAGE>

                Proved Oil and Gas Reserves at December 31, 1996
===============================================================================
                                                                  Present Value
                                 Oil        Gas      Future Net     of Future
                                (Bbls)     (Mcf)      Revenues   Net Revenues(1)

Proved reserves.............  2,432,711  8,835,929  $ 48,430,862   $ 27,570,370
Proved developed producing
reserves....................  2,380,522  7,369,964  $ 44,824,792   $ 26,670,314

===============================================================================

     (1) Present  value of future net revenues  before  deducting  the impact of
         federal and state income taxes (discounted at 10%).

     The future net revenues are  determined  by using  estimated  quantities of
proved reserves and proved developed producing reserves and the periods in which
they are  expected to be  developed  and  produced  based on  December  31, 1996
economic  conditions.  The  estimated  future  production is priced based on the
actual  prices  in  effect  at  December  31,  1996,   except  where  fixed  and
determinable price escalations are provided by contract. The resulting estimated
future  gross  revenues  are reduced by  estimated  future  costs to develop and
produce the proved reserves based on December 31, 1996 cost levels,  but not for
debt  service,   general  and  administrative  expense  and  income  taxes.  For
additional  information  concerning  the  discounted  future net  revenues to be
derived  from these  reserves and the  disclosure  of the  standardized  measure
information  in  accordance  with  the  provisions  of  Statement  of  Financial
Accounting  Standards  No. 69,  see  "Supplementary  Information  on Oil and Gas
Producing Activities (unaudited)" at page F-12 herein.

     The reserve data set forth in this Form 10-KSB  represents  only estimates.
Reserve   engineering  is  a  subjective   process  of  estimating   underground
accumulations  of crude oil and  natural gas that cannot be measured in an exact
manner.  The  accuracy of any  reserve  estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result,  estimates of different  engineers may vary.  In addition,  results of
drilling,  testing and  production  subsequent  to the date of an  estimate  may
justify revision of such estimate.  Accordingly,  reserve estimates often differ
from the quantities of crude oil and natural gas that are ultimately  recovered.
The  meaningfulness  of such estimates is highly  dependent upon the accuracy of
the assumptions upon which they were based.

Oil and Gas Production, Sales Prices and Production Costs

     The following table sets forth  information  with respect to production and
average product prices  attributable  to the Company's  ownership of royalty and
working  interests in producing  properties,  and, with respect to properties in
which the Company  owns a working  interest,  the  production  costs  (including
production  taxes  and  transportation  charges)  per  equivalent  barrel of oil
produced for the periods indicated.


==============================================================================
                                           Royalty Interests
                        ------------------------------------------------------
                               1996               1995               1994
                        -----------------  -----------------  ----------------
Production:
   Oil (Bbls)...........           57,137             64,500            58,137
   Gas (Mcf)............          393,114            372,291           370,678

Average Sales Prices:
   Oil (per Bbl)........           $20.13             $16.51            $15.03
   Gas (per Mcf)........             2.12               1.48              1.81

==============================================================================

                                      -11-
<PAGE>

==============================================================================
                                       Working Interests
                        ------------------------------------------------------
                              1996               1995               1994
                        -----------------  -----------------  ----------------
Production:
   Oil (Bbls)..........           182,388            165,221           129,684
   Gas (Mcf)...........           864,916            942,016           927,881

Average Sales Prices:
   Oil (per Bbl).......            $20.16             $16.01            $14.69
   Gas (per Mcf).......              1.97               1.39              1.63

Average direct 
     operating costs per
     barrel of oil 
     equivalent(1) ....             $9.03              $6.13             $5.22

==============================================================================

(1)  Barrels of oil equivalent are determined  using the ratio of six Mcf of gas
     to one barrel of crude oil, condensate or natural gas liquids. See Item 6.,
     Management's  Discussion  and  Analysis,  for further  discussion  of these
     costs.

ITEM 3. LEGAL PROCEEDINGS

Saltwater Contamination Claims

On June 13, 1996, the Company and HSOG filed suit in the United States  District
Court for the Eastern  District of Oklahoma  against Mobil Oil  Corporation  and
Mobil Exploration & Production U.S., Inc. (collectively  "Mobil"). This suit was
styled The Home-Stake Royalty Corporation and The Home-Stake Oil & Gas Company v
Mobil Oil  Corporation and Mobil  Exploration & Production  U.S., Inc. (Case No.
CIV-96-271-S).  This action concerned  Mobil's operation of a waterflood unit in
which the Company and HSOG each own a 9% working interest.  The Company and HSOG
sought actual  damages,  punitive  damages and equitable  relief in this matter.
Mobil  counterclaimed  for the  Company's  and  HSOG's  shares of  environmental
remediation and settlement costs which they had not paid. In late December 1996,
this case was settled,  with the Company and HSOG each  receiving  $365,000 from
Mobil. In connection with Mobil's  counterclaim,  the Company and HSOG agreed to
pay the unpaid environmental costs.

Other Matters

     The Company is also involved in various other minor actions  arising in the
normal  course  of  business.  In  the  opinion  of  management,  the  Company's
liabilities,  if any, in these matters and all others discussed in this Form 10-
KSB will not have a material effect on the Company's financial position, results
of operations or cash flows.



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

     There were no matters  submitted to the Company's  stockholders  during the
fourth quarter of the fiscal year ended December 31, 1996.





                                      -12-

<PAGE>
                                     PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     As of December 1, 1996 the Company had  approximately 250 holders of record
of its common stock.  The Company's  common stock is listed in the "pink sheets"
published by the National Quotation Bureau.  Trades in the stock are sporadic or
limited and, accordingly,  there is no established public trading market for the
common stock as defined in Item 201(a)(1) of SEC Regulation S-B.

     The  following  table  sets  forth the per share  amount of cash  dividends
declared and paid on the Company's common stock during the periods indicated.


                                                 Cash Dividends
                                              Declared and Paid Per
            Year ended December 31,                 Share of
                                                  Common Stock
     ------------------------------------- ---------------------------
     1996:    First Quarter                         $ 1.35
              Second Quarter                          1.35
              Third Quarter                            .90
              Fourth Quarter                           .90
     
     1995:    First Quarter                         $ 1.50
              Second Quarter                          1.50
              Third Quarter                           1.35
              Fourth Quarter                          1.35

     ===================================== ===========================


     The  Company  has  historically   paid  quarterly  cash  dividends  to  its
stockholders.  The Company's  Board of Directors  has adopted a dividend  policy
that  provides  for the payment of  quarterly  dividends,  dependent on numerous
factors,  including  future  earnings,  anticipated  capital  requirements,  the
financial condition and prospects of the Company,  and such other factors as the
Board  may deem  relevant.  In  addition,  future  dividends  may be  restricted
pursuant to the terms of the loan  agreement  between the Company and  Boatmen's
National Bank of Oklahoma. See "Management's  Discussion and Analysis" below for
a description of these restrictions.

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS

     The following  discussion  should be read in conjunction with the Company's
financial statements and notes thereto included elsewhere herein.

Results of Operations

     Net income for 1996  increased  197% from $620,835 in 1995 to $1,844,161 in
1996. The factors contributing to this increase are as follows:

     Oil sales increased  $1,117,808  (30%) primarily as a result of an increase
in the  average  sales  price per barrel  from $16.15 in 1995 to $20.16 in 1996,
coupled  with an  increase  in  production  of 9,799  barrels.  The  increase in
production was contributed by producing  properties the Company acquired in 1995
and 1996, along with new drilling in 1996.


                                      -13-

<PAGE>



     Gas  sales  increased  37%  ($678,099)  as a result of an  increase  in the
average  sales  price  from  $1.41  per Mcf in 1995 to  $2.02  per Mcf in  1996,
partially offset by a 4% decrease in production.

     Interest  income  increased  $12,488  primarily  as a result of more excess
funds available for investment.

     Gains on sales of assets increased 152% ($101,628) in 1996. The Company had
two major property sales in 1996. In November the Company sold its interest in a
Montgomery  County,  Texas field at a gain of $140,730.  In December the Company
sold its interest in 60 small, marginal properties at a small gain.

     Income from equity affiliates increased by $270,371.  In 1996 the Company's
principal equity investee,  HSOG,  reported net income of $1,437,674 compared to
$428,185 in 1995.

     Lease  operating   expenses  increased  $851,457  (53%)  due  primarily  to
non-recurring  costs  incurred in the settlement of claims by surface owners and
the  remediation of saltwater  contamination  on a property in which the Company
owns a 9% working interest.  Excluding this property,  lease operating  expenses
increased  $282,426.  This increase was associated  with  properties the Company
acquired  during 1995 and 1996, for which there are not comparable  period-costs
in the two years.  In  December  1996 and March 1997 the  Company  sold  several
marginal  properties  that incurred high operating  costs.  The properties  sold
incurred lease operating expenses in 1996 of $233,039.

     Production taxes increased 31% ($149,602) as a result of the higher oil and
gas sales described above.

     Dry hole costs  decreased  25%  ($44,686) in 1996. In 1996 there were 5 dry
holes  drilled (.45 net) at an average  cost of $293,300  per net well;  in 1995
there were 5 dry holes (.63 net)  drilled at an average cost of $280,400 per net
well.

     Condemned and abandoned  property  expense  decreased  $26,775 (32%).  1996
expense  includes  salvage credits of $12,488  received on a property  abandoned
during  the  first  quarter.   1995  expense  was  unusually  high  due  to  the
non-recurring  abandonment  of acreage  costs  associated  with three dry holes,
coupled with the expiration of leases on certain  non-producing acreage owned by
the Company.

     General and  administrative  expense decreased $275,566 (26%) in 1996. 1995
included  approximately  $139,600  incurred  in  connection  with the  Company's
unsuccessful  proposed merger into HSOG.  1996 expense  includes a credit in the
amount of $82,500,  representing  the  reimbursement  of legal expenses from the
Company's Directors' and Officers' Liability Insurance carrier.  This amount was
received  in  settlement  of a suit the  Company  and HSOG  brought  against the
carrier for recovery of certain costs  incurred by the Company in the successful
defense of the Company's directors in a lawsuit in 1991.

     Interest  expense  decreased  21%  ($66,222)  due to the  decreases  in the
Company's borrowings in 1996.

     The Company's  effective tax rate varies  significantly  from year to year,
due  principally  to the  significant  effects of statutory  depletion  which is
largely independent of pre-tax income. In addition, a portion of net income each
year is attributable  to the Company's  equity income from HSOG, for which there
is no corresponding  income tax provision required.  For additional  information
attributable  to each of the  factors see Note 4 to the  Consolidated  Financial
Statements on page F-10.

Financial Condition and Liquidity

     The Company's  operating  activities have  traditionally been self-financed
through  internally  generated cash flows. The principal uses of cash flows have
been to fund the Company's  exploration  and  production  activities and for the
payment of dividends to  stockholders.  The use of borrowed  funds has generally
been limited to the acquisition of producing oil and gas properties where future
revenues from such purchases are expected to fund the debt.

                                      -14-

<PAGE>



     In 1996,  the  Company  spent  $625,000  for  exploration  and  development
activities and $327,000 on  acquisitions.  The Company has budgeted $1.7 million
for  exploration  and  development  activities in 1997,  of which  approximately
$454,000 has been committed.  In November,  1995, the Boards of Directors of the
Company and HSOG changed the participation  agreement between the Companies such
that the Company increased its  participation  percentage in joint ventures with
HSOG to 60% in 1996; this relationship will continue in 1997.

     The working  capital  deficit at December 31, 1996 decreased  $446,172 from
1995,  due  primarily to the  increase in accounts  receivable,  reflecting  the
$365,000  due  from  Mobil in  connection  with the  settlement  of the  lawsuit
described in Item 3, Legal  Proceedings,  of this Annual  Report on Form 10-KSB.
The working  capital  deficit and the budgeted 1997  exploration and development
activities are expected to be financed from internally  generated cash flows. In
addition,  the  Company's  line of  credit  described  below is  expected  to be
extended into 1998.

     The  Company's  bank  note is due May 1,  1998  and  provides  for  monthly
principal  payments of  $80,355,  plus  interest.  Interest is at bank prime and
certain of the Company's  producing  properties are pledged to collateralize the
loan.  In  addition,  the  Company  has a bank line of  credit in the  amount of
$700,000  available  until May 1, 1997 which  provides  for monthly  payments of
interest on the  outstanding  borrowings at bank prime.  In connection with this
line of  credit,  the  Company  has  issued a letter of credit in the  amount of
$60,000, which is guaranteed by this line, and pays a commitment fee of one-half
of one  percent  (1/2%)  per annum on the  unused  portion  of the  line.  It is
presently expected that this line will be renewed by the bank at expiration.

     In 1996, the Company  aggressively  applied cash flows to the retirement of
its bank loans. Note payments were $2,008,875, over twice the required amount of
$964,260.  In 1997,  through the date of this report, the Company continued this
policy by paying $562,485 in excess of the required monthly  payments.  Based on
the outstanding balance at March 1, 1997, and assuming no additional payments in
excess of the required monthly payments,  the bank loan will be fully retired on
November 1, 1997.

     In connection with the Company's bank loans and credit facility,  there are
certain covenants which require,  among other things,  that the Company maintain
(i) a ratio of cash flow  (defined  in the loan  agreement  to be income  before
income taxes plus all depreciation, depletion and amortization and condemned and
abandoned property expense) to current maturities of long-term debt of more than
1.5 to 1.0, (ii) a ratio of total  liabilities  to  stockholders'  equity of not
more than 1.0 to 1.0, and (iii) a minimum net worth of not less than $9,000,000.
In addition,  the Company's  annual cash  dividends are limited to the lesser of
$425,000 or net income.

     In 1996 the  Company's  average  direct  operating  costs per barrel of oil
equivalent   increased  47%  to  $9.03.   This  increase  is  primarily  due  to
non-recurring  costs  incurred in the settlement of claims by surface owners and
the  remediation of saltwater  contamination  on a property in which the Company
owns  a 9%  working  interest.  Excluding  this  property,  the  average  direct
operating  costs per barrel of oil  equivalent  for the  Company  was $6.93.  In
December  1996 and March 1997 the  Company  sold,  at a gain,  several  marginal
properties that incurred high operating costs;  also excluding these properties,
direct operating costs per barrel of oil equivalent would have been $6.42.

     Average direct  operating  costs per barrel of oil equivalent are dependent
upon  several  factors,   including   principally  the  nature  of  a  company's
operations. For example, gas properties are generally more economical to operate
than oil properties.  Likewise, oil wells in a form of primary recovery (flowing
or pumping) are more economical to operate than oil wells in a form of secondary
recovery,  such as  waterfloods.  The  Company  has  large  interests  in  three
waterflood or water-drive operations. These properties contributed approximately
46% of the total working interest barrels of oil equivalent  production in 1996,
but were  responsible  for  approximately  74% of the  direct  operating  costs.
Excluding these waterflood properties,  the Company's direct operating costs per
barrel of oil equivalent in 1996 was $4.52.

     The Company  believes it will fully  realize its  deferred  tax assets and,
accordingly,  no  valuation  allowances  have  been  provided.  In  management's
opinion, the deferred tax assets will be realized as reductions in future income

                                      -15-

<PAGE>



taxes payable or by utilizing available tax planning  strategies.  Uncertainties
that may affect the ultimate  realization of these assets include future product
prices,  costs and tax rates.  Therefore,  the Company will periodically  review
these factors and determine whether a valuation allowance has become necessary.

Inflation

     In recent years inflation has not had a significant impact on the Company's
operations or financial  condition.  The general economic pressures limiting oil
and gas prices in recent years have generally been  accompanied by corresponding
downward pressure on costs to develop and operate oil and gas properties as well
as the costs of drilling and  completing  wells.  The impact of inflation on the
Company in the future  will  depend on the  relative  increases,  if any, in the
selling price of oil and gas and in the  Company's  operating,  development  and
drilling costs.

Forward Looking Statements

     Certain statements  included in this Annual Report on Form 10-KSB which are
not historical facts are "forward looking statements", including statements with
respect to oil and gas reserves, the number and location of wells to be drilled,
future  capital   expenditures   (including  the  amount  and  nature  thereof),
anticipated date of repayment of bank debt, extension of existing line of credit
and other such matters.  These forward  looking  statements are based on current
expectations,  estimates,  assumptions and beliefs of management; and words such
as  "expects",  "believes",   "anticipates",   "intends",  "plans"  and  similar
expressions  are intended to identify  such forward  looking  statements.  These
forward looking statements involve risks and uncertainties,  including,  but not
limited to:  dependence upon the prices for oil and natural gas which prices are
subject to significant  fluctuations in response to relatively  minor changes in
supply and demand for such products, market uncertainty, political conditions in
oil producing regions,  domestic and foreign government  regulations,  the price
and  availability  of  alternative   fuels  and  a  variety  of  other  factors;
competition in the  acquisition  of oil and gas properties and the  development,
production  and marketing of oil and natural gas;  operating  hazards  typically
associated with the exploration,  development,  production and transportation of
oil and natural gas; federal,  state and local laws relating to the exploration,
development,  production  and  marketing  of  oil  and  natural  gas,  including
environmental  and safety matters;  changes in laws and  regulations;  and other
factors,  most of which are beyond  the  control  of the  Company.  Accordingly,
actual results and  developments  may differ  materially from those expressed in
the forward looking statements.

ITEM 7. FINANCIAL STATEMENTS

     The information  required by this Item begins at page F-1 following page 19
hereof.

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

     There has been no change in accountants and no disagreements on any matters
of accounting  principles  or practices,  financial  statement  disclosures,  or
auditing scope or procedures.

                                    PART III

ITEM 9. DIRECTORS,  EXECUTIVE OFFICERS AND SECTION 16(a) BENEFICIAL OWNERSHIP
        REPORTING COMPLIANCE

     The information required by this Item is incorporated by reference from the
sections of the Company's definitive Proxy Statement for its 1997 Annual Meeting
of  Stockholders  (the "Proxy  Statement")  entitled  "Election  of  Directors",
"Executive  Officers of the Company" and  "Compliance  with Section 16(a) of the
Securities Exchange Act".



                                      -16-

<PAGE>



ITEM 10. EXECUTIVE COMPENSATION

     The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Executive Compensation".

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information required by this Item is incorporated by reference from the
section of the Proxy Statement  entitled  "Principal  Stockholders  and Security
Ownership of Management".

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required by this Item is incorporated by reference from the
section of the Proxy  Statement  entitled  "Certain  Relationships  and  Related
Transactions".

                                     PART IV

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

     (a) Exhibits:

     The following documents are included as exhibits to this Form 10-KSB. Those
exhibits  below  incorporated  by reference  herein are indicated as such by the
information  supplied  in  the  parenthetical  thereafter.  If no  parenthetical
appears after an exhibit, such exhibit is filed herewith.

Exhibit
Number            Description

     3.1  Restated  Certificate of  Incorporation  of the Company dated December
          20, 1991 (Filed as Exhibit 3.1 to the Company's Registration Statement
          on Form 10,  Registration  No.  0-19767  (the  "Form  10  Registration
          Statement")).

     3.2  Amended  Certificate  of  Incorporation  of the Company dated June 29,
          1994 (Filed as Exhibit  3.2 to  Amendment  1 to the  Company's  Annual
          Report on Form 10-KSB/A for the year ended December 31, 1994).

     3.3  Bylaws of the  Company,  as  amended  through  May 2,  1994  (Filed as
          Exhibit 3.2 to the Company's Annual Report on Form 10-KSB for the year
          ended December 31, 1994).

     4.1  Rights  Agreement and Indenture dated as of May 29, 1991,  between the
          Company and The Fourth National Bank of Tulsa (Filed as Exhibit 4.1 to
          the Form 10 Registration Statement).

     4.2  First  Amendment  to  Rights  Agreement  of  The  Home-Stake   Royalty
          Corporation  dated  April  15,  1992  (Filed  as  Exhibit  4.2  to the
          Company's Annual Report on Form 10-KSB for the year ended December 31,
          1992).

     4.3  Second  Amendment  to  Rights  Agreement  of  The  Home-Stake  Royalty
          Corporation  dated  February  10,  1995  (Filed as Exhibit  4.3 to the
          Company's Annual Report on Form 10-KSB for the year ended December 31,
          1994).

   *10.1  The Home-Stake  Companies Key Employee  Incentive Bonus Plan (Filed as
          Exhibit 10.2 to the Form 10 Registration Statement).

                                      -17-

<PAGE>



Exhibit
Number            Description


   *10.2  Employment  Agreement by and among Robert C. Simpson,  The  Home-Stake
          Oil & Gas Company and the Company  (Filed as Exhibit  10.4 to the Form
          10 Registration Statement).


   *10.3  Amendment to Employment  Agreement by and among Robert C. Simpson, The
          Home-Stake  Oil & Gas Company and the Company  dated  February 8, 1993
          (Filed as Exhibit 10.6 to the  Company's  Annual Report on Form 10-KSB
          for the year ended December 31, 1992).

   *10.4  The Home-Stake  Royalty  Corporation  Change in Control  Severance Pay
          Plan (Filed as Exhibit  10.8 to the  Company's  Annual  Report on Form
          10-K for the year ended December 31, 1991).

   *10.5  Form  of   Indemnity   Agreement   between  The   Home-Stake   Royalty
          Corporation  and each  Director,  dated May 14, 1996 (Filed as Exhibit
          10.1 to the Company's  Quarterly Report of Form 10-QSB for the quarter
          ended June 30, 1996).

    10.6  Second Amended and Restated Loan  Agreement  dated May 15, 1993 to the
          Loan  Agreement  dated July 1, 1991  between  the  Company and Bank IV
          Oklahoma,  N.A. (Filed as Exhibit 10.9 to the Company's  Annual Report
          on Form 10-KSB for the year ended December 31, 1993).

    10.7  First  Amendment and  Modification to Second Amended and Restated Loan
          Agreement dated May 15, 1994 between the Company and Bank IV Oklahoma,
          N.A.  (Filed as Exhibit 10.6 to the  Company's  Annual  Report on Form
          10-KSB for the year ended December 31, 1994).

    10.8  Third Amended and Restated Loan Agreement dated March 29, 1995 between
          the Company and Bank IV Oklahoma,  N.A.  (Filed as Exhibit 10.7 to the
          Company's Annual Report on Form 10-KSB for the year ended December 31,
          1994).

    10.9  First  Amendment and  Modification to Loan Agreement dated May 1, 1996
          to the Third Amended and Restated Loan Agreement  dated March 29, 1995
          between the Company and Bank IV Oklahoma,  N.A. (Filed as Exhibit 10.1
          to the Company's Quarterly Report of Form 10-QSB for the quarter ended
          June 30, 1996).

    10.10 Second Amendment and  Modification  Agreement dated May 1, 1996 to the
          Third Amended and Restated Loan Agreement dated March 29, 1995 between
          the Company and Bank IV Oklahoma,  N.A.  (Filed as Exhibit 10.3 to the
          Company's  Quarterly  Report of Form 10-QSB for the quarter ended June
          30, 1996).

     27   Financial Data Schedule.


         *    Management contract or compensatory plan or arrangement.

    (b)  Reports on Form 8-K.

     No reports on Form 8-K were filed  during the fourth  quarter of the fiscal
year ended December 31, 1996.


                                      -18-

<PAGE>


                                   SIGNATURES

     In accordance  with Section 13 or 15(d) of the Exchange Act, the Registrant
has  caused  this Form  10-KSB to be  signed on its  behalf by the  undersigned,
thereunto duly authorized.

                                        THE HOME-STAKE ROYALTY CORPORATION



Date:    March 26, 1997          By:    /s/ Robert C. Simpson
                                        ---------------------
                                        Robert C. Simpson
                                        Chairman of the Board,
                                        Chief Executive Officer,
                                        President and Treasurer

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

         Signature                       Title                      Date


/s/ Chris K. Corcoran           Director, Executive Vice        March 26, 1997 
------------------------------  President, Chief Financial                   
Chris K. Corcoran               Officer and Corporate 
                                Secretary
                                (Principal Financial 
                                 and Accounting Officer)

/s/ L.W. Allegood               Director                        March 26, 1997
------------------------------
L.W. Allegood

/s/ Larry F. Grindstaff         Director                        March 26, 1997
------------------------------
Larry F. Grindstaff

/s/ Ronald O. Gutman            Director                        March 26, 1997
------------------------------
Ronald O. Gutman

/s/ Joseph J. McCain, Jr.       Director                        March 26, 1997
------------------------------
Joseph J. McCain, Jr.

/s/ I. Wistar Morris, III       Director                        March 26, 1997
------------------------------
I. Wistar Morris, III


                                      -19-

<PAGE>


                       THE HOME-STAKE ROYALTY CORPORATION

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Covered by Report of Independent Auditors

Report of Independent Auditors...................................        F-2
Consolidated Balance Sheets as of December 31, 1996 and 1995.....        F-3
Consolidated Statements of Income and Retained Earnings
  for the years ended December 31, 1996 and 1995.................        F-4
Consolidated Statements of Cash Flows for the years ended
  December 31, 1996 and 1995.....................................        F-5
Notes to Consolidated Financial Statements.......................        F-6


Not Covered by Report of Independent Auditors

Supplementary Information on Oil and Gas Producing Activities for
  the years ended December 31, 1996 and 1995 (unaudited).........       F-12


                                       F-1

<PAGE>

                         REPORT OF INDEPENDENT AUDITORS



To the Board of Directors and Stockholders
The Home-Stake Royalty Corporation

We have  audited  the  accompanying  consolidated  financial  statements  of The
Home-Stake Royalty  Corporation listed in the accompanying index to consolidated
financial statements (Item 7). These financial statements are the responsibility
of the  Company'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,  the financial  statements  listed in the accompanying  index to
consolidated  financial  statements  (Item 7) present  fairly,  in all  material
respects,   the  consolidated  financial  position  of  The  Home-Stake  Royalty
Corporation at December 31, 1996 and 1995, and the  consolidated  results of its
operations  and its cash  flows  for the years  then  ended in  conformity  with
generally accepted accounting principles.


                                                           /s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 21, 1997


                                       F-2

<PAGE>



                       THE HOME-STAKE ROYALTY CORPORATION
                           CONSOLIDATED BALANCE SHEETS
                           December 31, 1996 and 1995

                                     ASSETS

                                                          1996         1995
                                                          ----         ----
Current assets:
  Cash and cash equivalents........................ $    626,864   $    564,875
  Accounts receivable..............................    1,469,877      1,024,200
  Receivable from affiliate........................       66,213        195,320
  Prepaid expenses.................................      255,957        144,726
                                                    ------------   ------------
         Total current assets......................    2,418,911      1,929,121

Investments (Note 2)...............................    3,592,495      3,223,735

Property and equipment, at cost:
  Producing oil and gas leases (working interests).   21,063,614     23,972,671
  Producing oil and gas royalties..................    2,842,116      2,872,257
  Nonproducing oil and gas properties..............      837,271        818,622
  Office equipment and other.......................      492,244        484,089
                                                    ------------   ------------
                                                      25,235,245     28,147,639
  Less accumulated depreciation, depletion
      and amortization.............................   16,437,277     18,356,014
                                                    ------------   ------------
            Net property and equipment.............    8,797,968      9,791,625

Other assets.......................................       24,119         21,288
                                                    ------------   ------------
                                                    $ 14,833,493   $ 14,965,769
                                                    ============   ============

                      LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
  Accounts payable and accrued liabilities......... $  1,514,282   $  1,461,650
  Dividends declared...............................       62,827         94,241
  Income taxes payable.............................       75,198          5,745
  Bonus payable....................................       20,253         49,412
  Current notes payable (Note 3)...................      964,260        964,260
                                                    ------------   ------------
         Total current liabilities.................    2,636,820      2,575,308
Long-term notes payable (Note 3)...................      401,775      2,410,650
Deferred income taxes (Note 4).....................      773,200        488,138
Commitments and Contingencies (Note 6)
Stockholders' equity (Note 7):
  Preferred stock, $1 par value -
    200,000 shares authorized; none issued
  Common stock, $40 par value -
    100,000 shares authorized and issued...........    4,000,000      4,000,000
  Additional paid-in capital.......................    6,000,000      6,000,000
  Retained earnings................................    4,385,862      2,855,837
                                                    ------------   ------------
                                                      14,385,862     12,855,837
  Less treasury stock, at cost - 30,192 shares.....    3,364,164      3,364,164
                                                    ------------   ------------
         Total stockholders' equity................   11,021,698      9,491,673
                                                    ------------   ------------
                                                    $ 14,833,493   $ 14,965,769
                                                    ============   ============
                             See accompanying notes.



                                       F-3

<PAGE>



                       THE HOME-STAKE ROYALTY CORPORATION
             CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
                     Years ended December 31, 1996 and 1995



                                                      1996              1995
                                                      ----              ----
Revenues:
     Oil sales.....................................  $ 4,827,826    $ 3,710,018
     Gas sales.....................................    2,536,078      1,857,979
     Lease bonuses and rentals.....................       23,294         24,122
     Interest......................................       65,446         52,958
     Gain on sales of assets.......................      168,664         67,036
     Income from equity affiliates.................      389,972        119,601
     Other.........................................      202,184        176,854
                                                     -----------    -----------
                                                       8,213,464      6,008,568
Costs and expenses:
     Lease operating expenses......................    2,444,121      1,592,664
     Production taxes..............................      631,600        481,998
     Depreciation, depletion and amortization......    1,351,335      1,425,935
     Dry hole costs................................      131,975        176,661
     Condemned and abandoned properties............       55,668         82,443
     General and administrative expense............      781,480      1,057,046
     Interest expense..............................      249,692        315,914
     Property, franchise and other taxes...........      110,736        107,203
                                                     -----------    -----------
                                                       5,756,607      5,239,864
Income before provision for income taxes...........    2,456,857        768,704

Provision for income taxes (Note 4):
     Current.......................................      327,634         73,046
     Deferred......................................      285,062         74,823
                                                     -----------    -----------
                                                         612,696        147,869
                                                     -----------    -----------
Net income.........................................    1,844,161        620,835

Retained earnings at beginning of year.............    2,855,837      2,632,908

Cash dividends ($4.50 per share - 1996, 
     $5.70 per share - 1995).......................     (314,136)      (397,906)
                                                     -----------    -----------

Retained earnings at end of year...................  $ 4,385,862    $ 2,855,837
                                                     ===========    ===========

Weighted average number of shares outstanding......       69,808         69,808
                                                          ======         ======

Net income per share of common stock...............       $26.42         $ 8.89
                                                          ======         ======
                             See accompanying notes.


                                       F-4

<PAGE>



                       THE HOME-STAKE ROYALTY CORPORATION
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                     Years ended December 31, 1996 and 1995


                                                         1996          1995
                                                         ----          ----
Operating activities:
  Oil and gas sales, net of production taxes.......  $ 6,600,732    $ 4,992,099
  Lease bonuses and rentals........................       23,294         24,122
  Interest.........................................       65,446         52,958
  Other............................................      202,184        176,854
                                                     -----------    -----------
                                                       6,891,656      5,246,033 

  Cash paid to suppliers and employees.............    3,595,153      2,276,663
  Interest paid....................................      249,692        323,540
  Property, franchise and other taxes..............      110,736        107,203
  Income taxes paid................................      224,756         50,480
                                                     -----------    -----------
                                                       4,180,337      2,757,886
    Net cash provided by operating activities......    2,711,319      2,488,147

Investing activities:
  Proceeds from sales of property and equipment....      362,260        153,696
  Acquisition of property and equipment............     (523,073)    (3,386,054)
  Acquisition of investments.......................     (202,558)            --
  Dividends from equity affiliate..................       71,022         99,432
                                                     -----------    -----------
    Net cash used in investing activities..........     (292,349)    (3,132,926)

Financing activities:
  Proceeds from notes payable......................           --      2,435,680
  Note payments....................................   (2,008,875)    (1,110,460)
  Cash dividends paid..............................     (348,106)      (404,785)
                                                     ------------   -----------
    Net cash provided by (used in) financing 
          activities...............................   (2,356,981)       920,435
                                                     -----------    -----------
Net increase in cash...............................       61,989        275,656
Cash and cash equivalents at beginning of year.....      564,875        289,219
                                                     -----------    -----------
Cash and cash equivalents at end of year...........  $   626,864    $   564,875
                                                     ===========    ===========

Reconciliation of net income to net cash 
     provided by operating activities:
Net income.........................................  $ 1,844,161    $   620,835
Reconciling adjustments:
  Depreciation, depletion and amortization.........    1,351,335      1,425,935
  Gain on sales of assets..........................     (168,664)       (67,036)
  Income from equity affiliates....................     (389,972)      (119,601)
  Dry hole costs and condemned and abandoned
    properties.....................................      187,643        259,104
  Deferred income taxes............................      285,062         74,823
  Changes in other assets and liabilities:
    Accounts receivable............................     (316,570)       308,091
    Prepaid expenses and other assets..............     (114,062)       (29,552)
    Accounts payable...............................       (7,908)        (3,832)
    Other liabilities..............................       40,294         19,380
                                                     -----------    -----------
Net cash provided by operating activities..........  $ 2,711,319    $ 2,488,147
                                                     ===========    ===========
                             See accompanying notes.

                                      F-5
<PAGE>

                       THE HOME-STAKE ROYALTY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Description of business

The  Home-Stake  Royalty  Corporation is an  "independent  oil and gas producer"
actively engaged in the acquisition,  exploration, development and production of
oil and gas properties.  Oil and gas  exploration and production  activities are
subject to numerous risks inherent in the business. These include the volatility
of oil and gas prices,  environmental  concerns  and  governmental  regulations,
general  business risks and hazards  involving the  acquisition and operation of
oil and gas properties,  the ability to continue to find new reserves to replace
those being  depleted and the highly  competitive  nature of the  business.  Its
principal geographic operating areas lie within the states of Oklahoma,  Montana
and Texas.

Note 1 - Summary of significant accounting policies

Principles of consolidation

The consolidated  financial  statements  include the accounts of the Company and
its wholly owned  subsidiary Alden Gas Gathering  Company.  The equity method is
used when the Company has a 20% to 50%  interest in other  companies.  Under the
equity  method,  original  investments  are recorded at cost and adjusted by the
Company's  share of  undistributed  earnings  and  losses  of  these  companies.
Dividends and distributions are credited against the investment when received.

Use of Estimates in the Preparation of Financial Statements

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

One of the most  significant  estimates made by the Company involves its oil and
gas reserves.  The Company  amortizes  its costs of producing  properties on the
unit-of-production  method over the estimated remaining reserves of the Company.
Since  estimates of remaining  oil and gas  reserves are highly  subjective  and
subject to constantly changing conditions,  most of which are beyond the control
of the Company,  it is reasonably  possible that the  Company's  estimates  will
change over time, affecting the rates of amortization. In addition, in assessing
whether any  impairment  to the  carrying  values of  producing  properties  has
occurred,  these same  estimates of oil and gas reserves are used.  Consequently
impairment adjustments to the carrying values are reasonably possible.

Fair Value of Financial Instruments

The carrying amounts for cash and cash equivalents and notes payable reported in
the balance sheets approximate fair value.

Cash and cash equivalents

The Company includes  certificates of deposit and money market funds in cash and
cash equivalents  since such amounts are readily  convertible into known amounts
of cash.

Credit risks

The Company  sells its oil and gas  production,  which is located  primarily  in
Montana, Oklahoma and Texas, directly or indirectly to numerous oil refiners and
pipeline  companies without  collateral.  In addition,  the Company has numerous
working  interest owners to whom it grants credit on wells in which it serves as
operator. Substantially all of these owners are industry partners or individuals
who invest in oil and gas drilling  ventures.  The Company  believes its credits
risks are limited  due to nature of its  business  and partner  base and has not
incurred any significant losses in connection therewith.

                                       F-6

<PAGE>


            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note 1 - Summary of significant accounting policies (continued)

Environmental costs

Environmental  liabilities,  which  historically  have  not been  material,  are
recognized  when it is probable  that a loss has been incurred and the amount of
that loss is reasonably estimable.  Environmental liabilities, when accrued, are
based upon estimates of expected future costs without  discounting.  At December
31, 1996 there are no such costs accrued.  The Company's policy is in compliance
with Statement of Position 96-1, Environmental  Remediation Liabilities,  issued
by the Accounting  Standards  Executive  Committee of the American  Institute of
Certified Public Accountants and issuance of this statement had no impact on the
Company's financial position or results of operations.

Property and equipment

The Company follows the successful  efforts method of accounting for its oil and
gas  operations.  Costs  of  productive  oil or gas  wells,  as well as costs of
acquiring producing  and  nonproducing oil and gas  properties, are capitalized.
Exploratory costs, annual delay rentals and exploratory dry holes are expensed.

Depreciation, depletion and amortization of producing properties are provided on
the   unit-of-production   method  based  on   estimates  of  proved   reserves.
Depreciation  of other  property and equipment is provided on  straight-line  or
accelerated methods over estimated useful lives.

In 1995 the Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of" (SFAS No. 121). Adoption of SFAS No. 121, which generally limits
the carrying value of producing  properties to their discounted estimated future
net cash  flows,  had no  retroactive  impact on net  income  in 1995  since the
Company has followed a similar policy since 1986.  Adjustments under this policy
are included in depreciation, depletion and amortization and totaled $91,107 and
$139,031 in 1996 and 1995, respectively.

Nonproducing  oil and gas properties  include both perpetual  mineral rights and
term leasehold  interests.  The perpetual  mineral rights are  written-off  when
unsuccessful  exploration information is obtained. The Company does not maintain
an  extensive  inventory  of  nonproducing  leasehold  interests,   rather  such
interests are acquired in connection  with specific  drilling  objectives.  Such
nonproducing  leasehold  interests are  written-off  or reserved as warranted by
drilling results.

Renewals and betterments are capitalized; maintenance and repairs are charged to
expense.  Replacement of individual  items of lease  equipment are  capitalized.
When  leases  or  other  assets  are  sold or  retired,  the  cost  and  related
accumulated  depreciation,  depletion and  amortization  are eliminated from the
accounts and the resulting  gain or loss is recognized in income.  The Company's
historical  experience  has been that the salvage value of equipment on property
abandonments  is  sufficient  to  cover  the  costs  of  dismantlement  and site
restoration. Therefore, the Company does not accrue such costs and salvage value
is not considered in calculating property amortization.

Oil and gas sales

The  Company  sells  most of its  crude  oil and  natural  gas  concurrent  with
production and does not store significant  volumes for future sales.  Revenue is
recognized on the "sales method" when oil and gas are sold.

Income taxes

Certain  income and  expense  items are  recorded  in one year in the  financial
statements and are reported in a different  year in the income tax return.  Such
items  generally  include  tax credit  carryforwards,  intangible  drilling  and
development costs,  depreciation and depletion.  The tax effects associated with
these  differences are recorded in these  financial  statements and described as
"deferred income taxes".


                                       F-7

<PAGE>


            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note 2 - Related party transactions and investments

The Company is under common  management  with The  Home-Stake  Oil & Gas Company
("HSOG"),  with which it frequently  participates  jointly in the acquisition of
mineral and leasehold  interests and in exploration and development  activities.
Each company  generally  owns an equal interest in the oil and gas properties in
which they  jointly  participate,  however  such  interests  may vary.  Only the
Company,  however,  serves as operator on  properties  that are not  operated by
outside parties.

In 1995 the  Boards of  Directors  of the  Company  and HSOG voted to change the
participation  arrangement  between the Companies such that effective January 1,
1996, the Company  participated with a 60% interest in joint ventures (drilling,
acquisitions  and/or other investments)  between the Company and HSOG, with HSOG
participating  in  such  ventures  with  a  40%  interest.   Joint  general  and
administrative  expenses continue to be shared on a 50-50 basis. The Boards felt
this  change was in the best  interests  of each  company,  based on a review of
their  respective  financial  conditions.   This  participation  arrangement  is
reviewed  by the Boards on an annual  basis and future  changes  will be made as
circumstances, in the judgement of the Boards, require.

In accordance  with oil and gas industry  practice,  the oil and gas ventures in
which both companies  participate are considered to be joint, but separate.  For
those properties  operated by outside parties,  each Company is generally billed
separately  for their  share of  operating  and  drilling  costs and  separately
reimburse the operator for such costs.  For properties  operated by the Company,
HSOG is billed for such costs monthly by the Company.

Payroll  costs for  personnel  are paid by the Company and HSOG  reimburses  the
Company  for its  one-half  share of such  costs.  For  substantially  all other
general and administrative  costs, each Company separately pays for its one-half
share.

For the two years  ended  December  31,  the  Company  paid or  billed  HSOG the
following amounts:

                                                            1996        1995
                                                            ----        ----
Paid:
  Oil and gas sales, net of production taxes.......      $ 451,941   $  231,235
Billed:
  Property and equipment...........................         82,838      337,076
  Lease operating expenses.........................        818,886      693,033
  Payroll costs....................................        494,243      455,331

All revenues and expenses  described above are paid by the respective company in
cash on a monthly basis.

In November 1996, the Company  acquired an additional  1,928 shares of HSOG at a
cost  of  $195,178.  At  December  31,  1996,  the  Company  owns  33.9%  of the
outstanding  common stock of HSOG and accounts for its  investment in HSOG using
the equity method. In November 1996, HSOG acquired an additional 1,493 shares of
the Company.  At December 31, 1996,  HSOG owns 19.3% of the  outstanding  common
stock of the  Company.  In  addition,  the Company  owns a 41% interest in Alden
Pipeline  Company,  a general  partnership  carried on the equity method.  These
investments  do not have quoted market  values.  In March 1997, the Company sold
its interest in Alden Pipeline Company and the related producing properties at a
gain of approximately $100,000.

At July 1, 1991, when the Company  adopted equity  accounting for its investment
in HSOG, the amount of investment  included costs of $1,527,439 in excess of the
underlying  equity in net assets which is being  amortized  into income over ten
years.



                                       F-8

<PAGE>


            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note 2 - Related party transactions and investments (continued)

At December 31, investments consisted of the following:


                                                        1996           1995
                                                        ----           ----

The Home-Stake Oil & Gas Company....................   $3,538,454    $3,167,260
Alden Pipeline Company..............................       54,041        56,475
                                                       ----------    ----------
                                                       $3,592,495    $3,223,735

The  Company  received   dividends   totaling  $71,023  and  $99,432  for  these
investments in 1996 and 1995, respectively.

Summarized  combined financial  information for HSOG and Alden Pipeline Company,
for which amounts are not material, is presented below:


                                                       Years ended December 31,
                                                         1996           1995
                                                         ----           ----
Income statement data:
   Revenues........................................    $7,759,424    $5,796,704
   Income before income taxes......................     1,858,854       430,902
   Net income (1)..................................     1,417,738       399,040

                                                              December 31,
                                                         1996           1995
                                                         ----           ----
Balance sheet data:
   Current assets..................................   $ 1,576,125   $   863,180
   Property and equipment (net)....................     8,735,493     9,892,774
   Other assets....................................     2,756,922     2,428,051
   Current liabilities.............................     2,299,840     2,115,646
   Noncurrent liabilities..........................     3,131,206     4,635,590
   Equity..........................................     7,637,494     6,432,769

     (1) Includes  $273,108  and  $109,788  in  1996  and  1995,   respectively,
         attributable to the equity earnings of the Company recorded by HSOG.

Note 3 - Notes payable

Notes payable at December 31, consist of the following balances:


                                                           1996         1995
                                                           ----         ----
Prime rate bank note due May 1, 1998, 
     requiring monthly principal payments
     of $80,355, plus interest.....................   $ 1,366,035   $ 3,374,910
Less current portion...............................       964,260       964,260
                                                      -----------   -----------
                                                      $   401,775   $ 2,410,650
                                                      ===========   ===========

Interest  is at bank  prime  (8.25%  at  December  31,  1996)  and  the  note is
collateralized  by certain of the Company's  producing  properties having a book
value at December 31, 1996 of  $5,254,816.  In addition,  the Company has a bank
line of  credit in the  amount of  $700,000  available  until May 1, 1997  which
provides for monthly payments of interest on the outstanding  borrowings at bank
prime. In connection  with this line of credit,  the Company has issued a letter
of credit in the amount of $60,000, which is guaranteed by this line, and pays a
commitment fee of one-half of one percent (1/2%) per annum on the unused portion
of the line.


                                       F-9

<PAGE>


            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note 3 - Notes payable (continued)

In connection  with the Company's  bank loans,  there are certain loan covenants
which require,  among other things,  that the Company maintain certain financial
ratios and minimum net worth  requirements.  In addition,  the Company's  annual
cash dividends are limited to the lesser of $425,000 or net income.

Note 4 - Income taxes

Deferred  income taxes  represent the net tax effects  associated with temporary
differences  in the net book  values  of  certain  assets  and  liabilities  for
financial  reporting  and income tax  purposes.  Significant  components  of the
Company's  deferred  income tax  liabilities  and assets at December  31, are as
follows:


                                                            1996        1995
                                                            ----        ----
Deferred tax liabilities:
  Intangible drilling costs........................     $  588,931   $  696,748
  Excess of tax over book depreciation.............        192,065      145,894
  Leasehold costs..................................        202,542       74,503
                                                        ----------   ----------
                                                           983,538      917,145
Deferred tax assets:
  Alternative minimum tax credit carryforwards.....        173,242      383,818
  Deferred compensation accrual....................         14,667       19,556
  Other (net)......................................         22,429       25,633
                                                        ----------   ----------
                                                           210,338      429,007
                                                        ----------   ----------
Net deferred tax liability.........................     $  773,200   $  488,138
                                                        ==========   ==========

The  reconciliation  of the income tax  provision  to the  "expected"  provision
computed at the statutory federal income tax rate is as follows:


                                                       1996               1995
                                                       ----               ----

Computed "expected" provision......................     $  835,331   $  261,359
Excess statutory depletion.........................       (101,828)    (126,323)
Amortization of investment in HSOG.................         51,934       51,934
Income from equity affiliates......................       (135,927)     (44,727)
Other..............................................        (36,814)       5,626
                                                        ----------   ----------
Provision for income taxes.........................     $  612,696   $  147,869
                                                        ==========   ==========

At December 31, 1996, the Company had nonexpiring alternative minimum tax credit
carryforwards  of  approximately  $185,800  available to reduce  future  federal
income  taxes,  the benefits of which have been  recognized  in these  financial
statements.

Note 5 - Benefit plans

Effective January 1, 1994 the Company and HSOG adopted The Home-Stake  Companies
Profit  Sharing  401(k) Plan.  The plan covers  substantially  all the Company's
employees  that have  completed one year of service and provides for a mandatory
Company  contribution  equal  to  3%  of  the  employee's  compensation  and  an
additional matching Company  contribution of up to 3%. Company  contributions to
the Plan were $22,288 and $23,048 in 1996 and 1995, respectively.





                                      F-10

<PAGE>


            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note 6 - Commitments and contingencies

The Company has a  non-cancelable  operating  lease  covering  its office  space
through  December 30, 2000.  This lease  provides for annual rental  payments of
$55,908, subject to an annual expense adjustment.

On June 13, 1996, the Company and HSOG filed suit in the United States  District
Court for the Eastern  District of Oklahoma  against Mobil Oil  Corporation  and
Mobil Exploration & Production U.S., Inc. (collectively  "Mobil"). This suit was
styled The Home-Stake Royalty Corporation and The Home-Stake Oil & Gas Company v
Mobil Oil  Corporation and Mobil  Exploration & Production  U.S., Inc. (Case No.
CIV-96-271-S).  This action concerned  Mobil's operation of a waterflood unit in
which the Company and HSOG each own a 9% working interest.  The Company and HSOG
sought actual  damages,  punitive  damages and equitable  relief in this matter.
Mobil  counterclaimed for the Company's and HSOG's shares of environmental costs
which they had not paid. In late December 1996, this case was settled,  with the
Company and HSOG each  receiving  $365,000  from Mobil which was credited to the
carrying value of the Company's  investment in the property.  In connection with
Mobil's   counterclaim,   the   Company  and  HSOG  agreed  to  pay  the  unpaid
environmental  costs.  In January  1997,  the Company and HSOG filed claims with
their pollution  insurance  carrier for the  reimbursement of $187,800  ($93,900
each  company),  representing  the Company's  share of surface owner  settlement
costs paid.  The  Company has not  received a response to this claim and has not
accrued any amounts  attributable to the expected  insurance  reimbursement.  In
addition,  the operator is still  working to reach  settlements  with  remaining
surface  owners.  It is currently  estimated  that the  Company's  share of such
additional costs may total as much as $50,000.  However, any amounts paid by the
Company should be covered under the Company's pollution insurance policy.

In addition,  the Company is involved in various other legal actions  arising in
the normal course of business.  In the opinion of management  and legal counsel,
the  Company's  liabilities,  if any, in these  matters will not have a material
effect on the Company's financial position, results of operations or cash flows.

Note 7 - Shareholder rights plan

On May 29,  1991,  the  Company  adopted a Rights  Plan and  distributed  to its
shareholders  one Right for each outstanding  share of common stock.  Each Right
entitles the holder to purchase one-tenth of an additional share of common stock
from the Company and acquire a note  payable  from the Company to the holder or,
under certain  circumstances,  purchase the stock of an acquiring company.  Upon
the occurrence of certain specified events related to a change in control of the
Company,  each holder of a Right (other than a potential acquiror) will have the
right to  acquire,  upon  exercise,  shares  of the  Company's  common  stock at
one-half of the then current market price. The Rights expire January 1, 2000 and
are exercisable  only if a person or group acquires 15% or more of the Company's
common  stock or commences a tender offer that would result in a person or group
acquiring 15% or more of the Company's  common stock.  The Rights are redeemable
in whole,  but not in part,  at a price of $.01 per  Right,  payable  in cash or
stock.


                                      F-11

<PAGE>


    SUPPLEMENTARY INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (unaudited)


Estimated quantities of proved oil and gas reserves

Changes in estimated  proved oil and gas reserve  quantities  are  summarized as
follows:


                                           1996                    1995
                                  ---------------------- ----------------------
                                      Oil        Gas         Oil          Gas
                                    (Bbls)      (Mcf)       (Bbls)       (Mcf)
Proved developed and
     undeveloped:
   Beginning of year...........   2,757,425   9,956,399   1,934,411   8,339,949
   Revisions of previous
     estimates.................    (184,463)   (525,793)    311,570     836,354
   Purchases of reserves 
     in-place..................      15,891     479,378     718,549   1,792,883
   Extensions, discoveries 
     and other additions.......      99,368     516,241      60,347     332,272
   Sales of reserves in-place..     (15,985)   (332,266)    (37,726)    (30,734)
   Production..................    (239,525) (1,258,030)   (229,726) (1,314,325)
                                 ----------  ----------  ----------  ----------
   End of year.................   2,432,711   8,835,929   2,757,425   9,956,399
                                 ==========  ==========  ==========  ==========
Proved developed producing:
  Beginning of year............   2,686,118   8,453,229   1,837,911   7,837,446
                                 ==========  ==========  ==========  ==========
  End of year..................   2,380,522   7,369,964   2,686,118   8,453,229
                                 ==========  ==========  ==========  ==========

The  Company's  share of net proved oil and gas reserves of investees  accounted
for on the equity method (see Note 2 to the Consolidated  Financial  Statements)
at December 31, 1996,  was 808,161  barrels of oil and 2,881,865 Mcf of gas, and
at December 31, 1995 was 865,832 barrels of oil and 3,083,948 Mcf of gas.

The estimates of oil and gas reserves were prepared by Company  employees and do
not include proved undeveloped reserves attributable to either royalty interests
(information is not available) or outside operated working interests (quantities
are not considered  significant to total Company proved reserves).  Furthermore,
these estimates do not include  reserves whose estimates or  recoverability  are
less precise,  commonly  referred to as "probable" or "possible"  reserves.  The
Company has no reserves outside the continental United States.

Standardized measure of discounted future net cash flows

In  accordance  with the  requirements  of  Statement  of  Financial  Accounting
Standards No. 69 ("SFAS No. 69") presented  below are  projections of future net
oil and gas cash flows (sales less production taxes, operating expenses, certain
development  costs and  estimated  income taxes) and related  present  values of
proved oil and gas reserves.  As required by SFAS No. 69, these  projections are
based on end of period prices and costs,  held constant for all future  periods.
Present values of the future net oil and gas cash flows were calculated  using a
10% discount  factor as required.  While this  information  was  developed  with
reasonable  care and disclosed in good faith,  it is emphasized that some of the
data are necessarily imprecise and represent only approximate amounts because of
the subjective  judgments involved in developing such information.  Accordingly,
this  information  may not  represent  the present  financial  condition  of the
Company or its expected future results.  This  information  does not include any
amounts applicable to "probable" or "possible"  reserves which may become proved
in the future.

Although these  disclosures  have been prepared in accordance  with SFAS No. 69,
this  information  does not  purport to  present  the fair  market  value of the
Company's  oil and gas  properties  or a fair  estimate of the present  value of
future cash flows  expected to be obtained  from their  production.  The reserve
estimates, while carefully made, may

                                      F-12

<PAGE>


    SUPPLEMENTARY INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (unaudited)


be significantly  revised based on future events. In addition,  estimates of the
timing of production,  actual prices realized and related  production  costs and
taxes may also vary significantly from those used in these calculations.


                                                          1996          1995
                                                          ----          ----
Future net cash flows:
  Oil and gas sales................................   $78,855,048   $58,721,117
  Lease operating expenses.........................   (23,802,053)  (21,566,821)
  Production taxes.................................    (6,147,291)   (4,502,273)
  Development costs................................      (474,842)     (658,575)
  Income taxes.....................................   (12,305,138)   (7,716,682)
                                                      -----------  ------------
                                                       36,125,724    24,276,766
     Less discount to present 
          value at 10% rate........................   (15,133,629)  (10,063,051)
                                                      -----------  ------------
Standardized measure of discounted 
     future net cash flows.........................   $20,992,095   $14,213,715
                                                      ===========   ===========

The Company's share of the  standardized  measure of discounted  future net cash
flows of investees  accounted  for on the equity method at December 31, 1996 and
1995 is $6,819,163 and $4,373,964, respectively.

The following  information  summarizes the principal changes in the standardized
measure of discounted future net cash flows.


                                                         1996           1995
                                                         ----           ----
Beginning of year..................................   $14,213,715   $11,806,618
Sales of oil and gas, net of production costs......    (4,288,183)   (3,493,335)
Net changes in prices and production costs.........    10,716,647    (1,824,540)
Extensions and discoveries.........................     1,303,483       474,414
Purchases of reserves-in-place.....................       573,138     4,592,387
Sales of reserves-in-place.........................      (438,724)     (210,156)
Revisions of previous quantity estimates...........    (2,022,227)    2,020,087
Net change in income taxes.........................    (2,169,336)     (138,730)
Other (net)........................................     1,682,210      (193,692)
Accretion of discount..............................     1,421,372     1,180,662
                                                      -----------   -----------
End of year........................................   $20,992,095   $14,213,715
                                                      ===========   ===========



                                      F-13

<PAGE>


    SUPPLEMENTARY INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (unaudited)

Costs incurred

Costs incurred in oil and gas producing activities include:


                                                           1996         1995
                                                           ----         ----
Proved property acquisition costs..................    $   327,008  $ 3,188,569
Unproved property acquisition costs................        137,518      181,377
Exploration costs..................................        400,468      131,301
Development costs..................................         87,181      237,725
                                                       -----------  -----------
                                                       $   952,175  $ 3,738,972
                                                       ===========  ===========

The Company's  share of costs  incurred in oil and gas  producing  activities of
investees  accounted  for on the equity method in 1996 and 1996 was $236,588 and
$1,170,096, respectively.


                                      F-14