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-
<PAGE>
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
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-Mos
<FISCAL-YEAR-END> Dec-31-1996
<PERIOD-END> Dec-31-1996
<CASH> 626,864
<SECURITIES> 0
<RECEIVABLES> 1,469,877
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,418,911
<PP&E> 25,235,245
<DEPRECIATION> 16,437,277
<TOTAL-ASSETS> 14,833,493
<CURRENT-LIABILITIES> 2,636,820
<BONDS> 401,775
0
0
<COMMON> 4,000,000
<OTHER-SE> 6,000,000
<TOTAL-LIABILITY-AND-EQUITY> 14,833,493
<SALES> 7,387,198
<TOTAL-REVENUES> 8,213,464
<CGS> 0
<TOTAL-COSTS> 3,075,721
<OTHER-EXPENSES> 187,643
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 249,692
<INCOME-PRETAX> 2,456,857
<INCOME-TAX> 612,696
<INCOME-CONTINUING> 1,844,161
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,844,161
<EPS-PRIMARY> 26.42
<EPS-DILUTED> 26.42
</TABLE>
