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1996 ANNUAL REPORT
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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 0-10697
[DORCHESTER LOGO] DORCHESTER HUGOTON, LTD.
(Exact name of registrant as specified in its charter)
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TEXAS 75-1829064
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
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9696 SKILLMAN STREET, SUITE 320-LB42, DALLAS, TEXAS 75243-8200
(Address of principal executive offices, including Zip Code)
Registrant's telephone number, including area code: (214) 340-3443
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
DEPOSITARY RECEIPTS FOR UNITS OF LIMITED PARTNERSHIP INTEREST IN DORCHESTER
HUGOTON, LTD.
(Title of Class)
INDICATE BY CHECK MARK WHETHER THE REGISTRANT: (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [X] NO [ ]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM
405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE
BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS
INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS
FORM 10-K. [X]
THE AGGREGATE MARKET VALUE OF THE VOTING SECURITIES HELD BY NON-AFFILIATES
OF THE REGISTRANT ON JANUARY 1, 1997 WAS $139,549,000.
AS OF FEBRUARY 1, 1997, THERE WERE OUTSTANDING DEPOSITARY RECEIPTS FOR
10,744,380 UNITS OF LIMITED PARTNERSHIP INTEREST IN DORCHESTER HUGOTON, LTD.
Documents Incorporated by Reference: None
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CROSS REFERENCE SHEET
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FORM 10-K ITEM
NUMBER AND CAPTION CAPTION IN FORM 10-K
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PART I:
1. Business................................................ Business and Properties of the
Partnership
2. Properties.............................................. Business and Properties of the
Partnership
3. Legal Proceedings....................................... Financial Information
4. Submission of Matters to a Vote of Security Holders..... None
PART II:
5. Market for Registrant's Common Equity
and Related Stockholder Matters......................... Depositary Receipts and the
Depositary Agreement
6. Selected Financial Data................................. Selected Financial Data
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... Management's Discussion and
Analysis of Financial Condition and
Results of Operations
8. Financial Statements and Supplementary Data............. Financial Information
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..................... None
PART III:
10. Directors and Executive Officers of the Registrant...... The Partnership
11. Executive Compensation.................................. The Partnership
12. Security Ownership of Certain Beneficial
Owners and Management................................... Principal Holders
13. Certain Relationships and Related Transactions.......... The Partnership
PART IV:
14. Exhibits and Reports on Form 8-K........................ Financial Information
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BUSINESS AND PROPERTIES OF THE PARTNERSHIP
Dorchester Hugoton, Ltd. (the "Partnership") has its principal place of
business at 9696 Skillman Street, Suite 320-LB42, Dallas, Texas 75243-8200
(telephone (214) 340-3443) with field offices in Hooker, Oklahoma and Amarillo,
Texas and employed fifteen full time permanent employees (not including General
Partners) as of January 1, 1997. The Partnership was formed on June 16, 1982 as
a Texas limited partnership pursuant to a Certificate and Agreement of Limited
Partnership (as amended, the "Partnership Agreement"), by Dorchester Gas
Corporation ("DGC") which contributed to the Partnership working interests in
certain natural gas properties in Kansas and Oklahoma. Depositary receipts
("Depositary Receipts") for units of limited partnership interest ("Units") were
distributed on August 20, 1982 to DGC stockholders of record as of July 2, 1982
in the form of a taxable property dividend on the basis of one Unit for each ten
shares of DGC common stock held. Neither DGC nor the Partnership received any
proceeds from the distribution of the Units and cash payments were made in lieu
of distributing fractional Units.
The Partnership's principal operating assets consist of working interests
and support facilities for properties that produce natural gas from the Hugoton
gas field in Kansas and Oklahoma. The Hugoton field is considered one of the
most prolific gas fields in the United States. All of the Partnership's current
working interest wells (except for infill wells in Kansas and replacement wells
in Oklahoma) were drilled and have been producing since prior to 1954.
OKLAHOMA PROPERTIES
The Partnership's Oklahoma working interests include 128 natural gas wells
(115.7 net wells) producing from the Guymon-Hugoton field on 80,501 gross
developed acres (74,501 net acres). It currently operates and owns interests in
117 wells in Oklahoma, of which the Partnership has a 100% working interest in
109 wells, working interests ranging from 50% to 88% in 5 wells and liquefiable
hydrocarbons interests only in the remaining 3 wells. The Partnership also has
working interests ranging from 25% to 50% per well in an 11 well group operated
by unaffiliated third parties.
Of the Partnership's 128 gas wells, 124 are delivered through a 131 mile
gas pipeline gathering system to the Partnership's Oklahoma gas compressor
station. Beginning November 1, 1994, the Partnership's new 5400 horsepower gas
compression and dehydration facility became operational and gas was delivered
direct (without processing) to Panhandle Eastern Pipe Line Company ("PEPL").
Numerous other transmission pipelines are also nearby. The total cost of these
facilities was $6.0 million which included offices and warehouse storage for
both field and compressor operations. The Partnership's portion of gas sales
averaged 17.1 million cubic feet per day ("MMCFD") during 1996. Centana Energy
or Williams Energy Services Company (formerly Williams Gas Marketing Company)
have purchased the Partnership's gas since November 1, 1994 generally at prices
slightly greater than an index price reflective of the spot market price in the
area.
Following Federal Energy Regulatory Commission approval, the Partnership
began delivery of gas from its Oklahoma compression facilities to Williams Gas
Processing -- Mid Continent Region Co., a subsidiary of the Williams Companies,
Inc. during December 1996. Williams Field Services Company subsequently
processes the gas at its newly constructed plant near Baker, Oklahoma and
returns the gas as directed by the Partnership to the available transmission
pipelines at the plant outlet which include Williams Natural Gas Company, PEPL,
and Natural Gas Pipeline Company of America ("NGPL"). The gas returned to the
Partnership for subsequent sale is of improved quality, including having the
contaminant nitrogen removed.
Prior to January 1, 1993, the Partnership's Oklahoma natural gas production
was sold at less than $.50/MMBtu under the 1946 Gas Purchase Contract, as
amended, (the "Contract") to NGPL. In early December, 1992, the Partnership
settled litigation against NGPL and amended the Contract. The amended Contract
provided that NGPL would pay for the residue gas from the Partnership's Oklahoma
properties at an indexed market price. Gas was sold under the amended contract
until termination by NGPL effective May 1, 1994. The Partnership's Oklahoma gas
was also subject to a
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June 16, 1982 Gas Processing Agreement (the "Agreement") between the Partnership
and a Parker & Parsley Petroleum Company subsidiary or affiliate (the successor
to Damson Oil Corporation & affiliates -- collectively referred to as "P&P"). As
a result, the Partnership's Oklahoma gas production was processed in P&P's
Hooker, Oklahoma gas processing plant where natural gas liquids were extracted
and the remaining gas ("residue gas") was delivered and sold to NGPL at the
plant outlet. The extraction of natural gas liquids requires the consumption of
some gas as fuel and the extraction itself shrinks the gas production in both
volume and heating value (referred to as "fuel and shrinkage"). The Agreement
provided, among other things, that P&P operate gas gathering pipelines, that P&P
retain the natural gas liquids extracted, and that the Partnership would receive
for fuel and shrinkage incurred the value of the gas produced at the wellhead
(including severance taxes) less amounts received for residue gas sales to NGPL.
From January 1, 1993 to May 1, 1994, P&P paid for this fuel and shrinkage at a
disputed value of under $.20/MCF. The Agreement terminated upon termination of
the Partnership's Contract with NGPL on May 1, 1994. ALL LITIGATION INVOLVING
FUEL AND SHRINKAGE AND OTHER ISSUES WAS SETTLED AUGUST 14, 1996 -- SEE NOTE 3 TO
FINANCIAL STATEMENTS.
Wells in the Guymon-Hugoton field are drilled into a 150 feet thick
geological formation commonly called the Chase Group. An average Partnership
well will encounter the top of the Chase Group approximately 2,700 feet below
the surface. This formation typically consists of non-productive shale rock
layers that separate the productive zones commonly called Herington, Krider,
Winfield and the deeper Fort Riley. At the time of drilling the Partnership's
wells (primarily during the late 1940's), the Fort Riley zone was considered to
contain salt water rather than natural gas and was frequently not penetrated.
Based on current information, the Fort Riley structure for the most part appears
to be full of water.
However, the Partnership believes that it is possible that some of the
Partnership acreage contains Fort Riley zones that are high enough structurally
to avoid excessive water saturation and be gas productive. It is commonly
believed that the shale layers have prevented "crossflow" or gas migration
between the Chase Group productive zones. For example, it is believed that gas
in the Fort Riley has not flowed upward to the Winfield. However, it is not
known to what extent, if any, gas from the Fort Riley has migrated laterally
over the 50+ years. If the Fort Riley zone does not contain salt water and is
found to have not migrated, additional reserves are possible. The Partnership's
existing wells are mechanically not capable of being deepened. Consequently, to
explore for additional reserves will require drilling a well and isolating the
Fort Riley zone for testing.
As previously stated in various Partnership Annual Reports on Form 10-K,
the Partnership has always considered such additional zones as possibly
productive but best characterized as "exploratory." Consequently, considering
the numerous unknown factors such as possible salt water and possible previous
migration of the Fort Riley, THE PARTNERSHIP URGES CAUTION IN PREDICTING THE
OUTCOME OF SUCH EXPLORATION.
At present, the Partnership is updating geological work and making
preparations to drill and test the Fort Riley zone by using a "replacement
well." Such a well would replace the existing well on the 640 acre unit.
Provided the Fort Riley zone appears to not be depleted and not saturated with
water, the replacement well would be designed to isolate in the well bore the
Fort Riley zone from other zones and commingle the gas at the wellhead on the
surface of the ground. Such separation of the zones will prevent the Fort Riley,
if productive, from simply flowing up the well bore into the lower pressured,
productive zones of the Chase Group. Should the Fort Riley be non-productive or
depleted, the other zones of the replacement well will either be completed or
the replacement well will be plugged and the old well reopened.
It has not yet been determined when the Partnership will seek state
regulatory permission to drill and test the Fort Riley. Also, it is not known at
this time how many wells should be attempted to evaluate the potential of the
Fort Riley formation.
The Partnership also has minor royalty interests in various producing
natural gas wells.
2
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KANSAS PROPERTIES
The Partnership currently operates and owns 100% of the working interest in
19 natural gas wells producing from the Kansas Hugoton field on 7,035 gross
developed acres. The natural gas from these operated wells is currently
delivered through a 20 mile gas gathering pipeline and compression facility
owned by the Partnership and is sold in the field at spot market prices. The
Partnership's portion of gas sales averaged 6.0 MMCFD during 1996.
During 1986, the Kansas Corporation Commission ("KCC") issued an order
authorizing infill drilling on 320 acre spacing. Previously, each gas well
required 640 acres. The Partnership drilled and completed on its operated
properties eight producers through 1990; one in 1995, and one in 1996. One
infill well was plugged in 1992 and another in 1993 for economic reasons. The
Partnership currently has available only one previously undrilled unit for an
additional infill well. The Partnership also participated in infill drilling on
non-operated properties in which the Partnership no longer has an interest (see
Note 3 to Financial Statements).
The Partnership also has minor overriding royalty interests in producing
natural gas wells in Kansas.
NATURAL GAS RESERVES AND OTHER FINANCIAL DATA
Information with respect to the Partnership's natural gas reserves and
other financial data is presented in Note 4 to the Financial Statements included
elsewhere herein.
PARTNERSHIP OPERATIONS
The Partnership has operated most of its properties since July 1, 1984.
Historically the cash necessary to pay the costs and expenses of operating the
Partnership and its properties, including debt service, has been provided by the
cash flow from the Partnership's producing properties. To the extent that
Partnership operations, including any future development of its properties,
require cash in excess of the Partnership's cash flow, the Partnership has
secured a financing commitment from a bank. See Note 2 to the Financial
Statements for a discussion regarding current bank borrowings.
REGULATION AND PRICES
The sale of natural gas has been subject to regulation by federal
authorities, specifically by the Federal Energy Regulatory Commission (also
referred to as the "FERC"), and production of natural gas is regulated by
various state agencies or authorities. The Partnership's operations are also
affected by various statutory controls or obligations and, in varying degrees,
by political developments and federal and state laws and regulations. Natural
gas production is affected by changing federal and state tax and other laws
which are specifically applicable to the oil and gas industry, by constantly
changing federal and state administrative regulations as well as possible
interruption or termination by government authorities due to ecological and
other considerations, etc. Allowable gas production rates have been, and should
continue to be, subject to conservation and environmental laws and regulations.
Both Kansas and Oklahoma regulate the amount of natural gas that can be
produced by assigning to each well or proration unit a monthly allowable rate of
production. The Partnership's allowable quantity of natural gas which may be
produced from its Kansas properties is regulated by the KCC. These allowables
increased April 1, 1994 primarily as a result of basic rule changes by the KCC.
Recent field wide state tests for the past two years show a higher than normal
decrease in the gas reservoir pressure of nearly all producers in our area of
the Kansas Hugoton field. Generally, the allowables for the Partnership's Kansas
wells began a slight trend downward in the last half of 1996. However,
allowables can change with market demand and production rates.
In 1995 Oklahoma reduced its statewide gas proration regulation, but
retained these regulations for the Guymon-Hugoton field. At present there are a
few producers in the Guymon-Hugoton field seeking to revise the 1995 Oklahoma
law in order to eliminate Guymon-Hugoton gas proration rules.
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The retention of gas proration field rules to regulate production is supported
by the Partnership along with several other producers. The Partnership believes
such field rules are proven conservation measures and necessary to protect
correlative rights and prevent waste. Kansas and Oklahoma also specifically
regulate the drilling of new or replacement oil and gas wells, the spacing of
wells, the prevention of waste of natural gas resources, environmental
protection and various other matters.
At present, the Guymon-Hugoton field is restricted by state conservation
regulations to a maximum of one well for each 640 acres (subject to minor
variances). Including the Partnership's 128 wells, there are 1,359 currently
producing gas wells in the Guymon-Hugoton Field owned by both independent
producers and major oil and gas companies. Currently, a few producers and
numerous other interested parties in the area are actively seeking either
regulatory or legislative changes to enable "increased density drilling" similar
to Kansas infill drilling on 320 acre spacing. At present, several producers in
the field are actively opposing such infill drilling. The difference in beliefs
appears to rest in whether such infill drilling results in increased reserves.
In 1989 the Oklahoma Corporation Commission concluded hearings on infill
drilling and determined the present density of one well per 640 acres was
adequate to drain the 640 acres. Numerous studies of the Kansas infill drilling
results have concluded that no new reserves were developed by infill drilling.
This conclusion is consistent with the Partnership's experience in Kansas.
A change or elimination in the existing Guymon-Hugoton field rules could
result in a large number of wells being drilled that are not needed to produce
the same gas that is being produced by the existing wells. The Partnership
believes it is not usually economically justifiable to drill a second well on
640 acres in Oklahoma just to produce the same gas as the original well, only
faster.
With the enactment of the Natural Gas Wellhead Decontrol Act of 1989, FERC
natural gas price controls were eliminated on January 1, 1993. Subsequently, the
pricing of all the Partnership's gas sales, both in Kansas and Oklahoma, is
primarily determined by supply and demand in the marketplace. This price can
fluctuate considerably. Since January 1996, the lowest price was $1.57/MMBTU in
September, 1996 and the highest was $4.095/MMBTU in January 1997. The
Partnership anticipates continued fluctuations in marketplace pricing.
The Partnership's 1996 gas sales were generally sold based upon slight
premiums above an index reflective of the market price of gas in the
Oklahoma -- Kansas area. Effective March 1, 1996 the Partnership's Kansas gas
was committed based on market prices to NorAm Energy Services, Inc. for one
year. In 1996 the Partnership's Oklahoma gas was sold on month to month
agreements to Williams Energy Services Company ("WESCO").
The FERC is currently allowing regulated transmission pipelines to transfer
or sell portions of their system classified or reclassified by the FERC as gas
gathering pipelines to non-regulated entities or affiliates. Most of the
Partnership's Oklahoma gas was not affected by any such sale or transfer and the
Partnership believes the effect in Kansas to be minimal since only one of the
two transmission pipelines to which the Partnership delivered gas became a
non-regulated gathering pipeline. Although the Partnership negotiated a March 1,
1996 agreement with Anadarko Gathering Company to provide gas transportation and
mainline compression previously provided by a regulated transmission pipeline,
such agreement has not been employed and the Partnership's gas from the 19
Kansas wells was delivered directly to a transmission pipeline. On May 1, 1996
the Partnership also negotiated a four year gas sales agreement with WFS Gas
Resources Company (now WESCO) providing for gathering, compression, and sale of
gas at market prices for four wells (three in which the Partnership has a
minimal interest) that are not connected to the Partnership's Oklahoma gas
gathering pipeline and compression facilities. This sales agreement replaced the
previously regulated gathering and compression services provided by Williams
Natural Gas Company.
COMPETITION
The energy industry in which the Partnership competes is subject to intense
competition among a large number of companies, both larger and smaller than the
Partnership, many of which have financial
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and other resources greater than the Partnership. All present natural gas
production in Oklahoma is sold under month to month contracts and Kansas is sold
on an annual contract. All sales have generally been based upon a price slightly
higher than an index price reflective of the spot market price in the area. See
Note 1 to the Financial Statements for a discussion regarding material
customers.
ENVIRONMENTAL LAWS AND REGULATIONS
The costs associated with the Partnership's compliance with environmental
laws and regulations has not had, and is not anticipated to have, a material
effect on its capital expenditures, earnings or competitive position. The
Partnership's gas production contains minimal contaminants other than nitrogen
which is inert and non-toxic. The Partnership's quarterly air emission tests at
its Oklahoma compression facility continue to comply with the Oklahoma
Department of Environmental Quality's air quality regulations. The Kansas
Department of Health and Environment ("KDHE") has advised the Partnership that a
permit was not required for the 1995 modifications to its Kansas compression
facility. In addition, one Kansas well underwent KDHE regulated non-hazardous
soil removal and disposal to remedy minor mercury contamination during 1996 at
minimal cost. No other Kansas well site required remedial attention.
DEPOSITARY RECEIPTS AND THE DEPOSITARY AGREEMENT
Immediately subsequent to its formation, all of the Partnership Units were
deposited with an authorized depository (effective August 21, 1995, American
Stock Transfer & Trust Company, 40 Wall Street, New York, New York 10005, the
"Depositary"), to be held in accordance with the Depositary Agreement. The
Depositary maintains an account with respect to the Units deposited for which it
has issued Depositary Receipts. Holders of Depositary Receipts (also referred to
as "Unitholders") may transfer, combine or subdivide them at any office of the
Depositary designated for such purpose. Unitholders may also surrender them to
the Depositary and, upon submission of such documents as the General Partners
may require, reclaim deposited Units. However, the Units will not be readily
transferable and any redeposit of Units against newly issued Depositary Receipts
will require 60 days advance written notice and is subject to certain other
conditions.
Since its formation the Partnership has split its Units twice. The first
split was a three-for-one (3-for-1) split of its Units effective October 15,
1987 and the second such split was a two-for-one (2-for-1) split effective July
26, 1989. Additional Units were distributed to Unitholders of record in October,
1987 and August, 1989, respectively. These non-taxable splits were made to
enhance the tradability of the Depositary Receipts evidencing the Units and
increased to 10,744,380 the number of Units presently outstanding. All per-Unit
information has been retroactively adjusted to give effect to these non-taxable
splits.
On May 7, 1996 the Partnership announced a program to purchase from time to
time up to 500,000 of the Partnership's Units. Such purchases may be made on the
open market, in private transactions, or otherwise. Purchases from the General
Partners are excluded from the repurchase program. All Units repurchased under
the program shall be retired resulting in a decrease in both Units issued and
Units outstanding. No Units will be held as "Treasury Units". There is no
assurance or obligation that the repurchase program will result in any purchase
of Units. The Partnership believes the repurchase program is a way to enhance
the value to our long-term investors by increasing a Unitholder's equity
ownership in natural gas producing properties rather than attempting
alternatives such as acquisition or exploration programs. To date, no Units have
been purchased by the Partnership.
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The Depositary Receipts have been traded on the Nasdaq Stock Market under
the symbol "DHULZ" since August 26, 1982. The quoted market prices and reported
trading volumes for 1996 and 1995 were as follows:
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1996 1995
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LOW HIGH VOLUME LOW HIGH VOLUME
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First Quarter.................... 10 3/4 13 1/2 482,000 11 1/2 12 1/4 224,000
Second Quarter................... 12 1/2 15 415,000 10 7/8 12 1/4 522,000
Third Quarter.................... 13 1/4 16 258,000 10 12 1/2 447,000
Fourth Quarter................... 14 1/2 15 1/2 330,000 10 3/4 13 352,000
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As of January 1, 1997, there were approximately 4,200 Unitholders.
During 1993 the National Association of Securities Dealers, Inc. (the
"NASD") adopted new governance rules for limited partnerships traded on the
Nasdaq Stock Market. In compliance with these rules, the Partnership established
in 1995 an Advisory Committee consisting of two independent advisors to function
as the Partnership's audit committee and to review and approve any transactions
between the Partnership and its General Partners, including any compensation and
benefits paid to the General Partners by the Partnership. The Partnership
Agreement was amended accordingly.
The Units and the Depositary Receipts are fully paid and non-assessable.
Each record holder of a Depositary Receipt evidencing the ownership of one or
more Units will, for purposes of the Texas Revised Limited Partnership Act
("TRLPA"), be an assignee with respect to the interests in the Partnership
represented by such Units. Each such assignee may become a Substituted Limited
Partner upon (i) the execution and delivery of a request and agreement to become
a Substituted Limited Partner, which includes a power of attorney to the General
Partners (ii) the approval of the General Partners to such admission as a
Substituted Limited Partner and (iii) the filing of an amended Certificate of
Limited Partnership evidencing the admission of such person as a Substituted
Limited Partner. If such action is not taken, Unitholders will remain assignees
of the interests of the Partnership represented by the Units. Under certain
circumstances, a Unitholder may not become a Substituted Limited Partner if such
holder is not an Eligible Citizen. Each Unitholder (whether an assignee or
Limited Partner) as of the last day of each month is allocated a pro rata share
of the Partnership's profits and losses for the month then ended, regardless of
whether such holder receives any cash distributions from the Partnership. Each
Unitholder of record (whether an assignee or Limited Partner) as of the
applicable record date is entitled to receive an allocable share of any cash
distributions made by the Partnership. The timing and amount of such
distributions is determined by the General Partners. In addition, the
Partnership's Loan Agreement with Bank One, Texas, NA requires the Partnership
capital to remain above certain specified amounts. The Partnership Agreement
provides that prior to the dissolution of the Partnership, the General Partners
shall determine the amount of cash available for distribution, if any, at least
as of the end of each calendar quarter.
Distributions per Unit have been as follows:
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YEAR ENDED DECEMBER 31,
QUARTER 1982 1983 1984 1985/86 1987 1988 1989/90/91 1992 1993 1994 1995 1996
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First................ N/A $ .02 $ .01 $ .01 $ .02 $ .03 $ .05 $ .05 $ .12 $ .17 $ .17 $ .17
Second............... N/A .01 .01 .01 .02 .04 .05 .05 .15 .17 .17 .17
Third................ $.01 .01 .01 .01 .03 .04 .05 .05 .17 .17 .17 .17
Fourth............... .02 .01 .01 .02 .03 .04 .05 .08 .17 .17 .17 .17
---- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total................ $.03 $ .05 $ .04 $ .05 $ .10 $ .15 $ .20 $ .23 $ .61 $ .68 $ .68 $ .68
==== ===== ===== ===== ===== ===== ===== ===== ===== ===== ===== =====
</TABLE>
Effective with the third quarter 1995 distribution, the Partnership's new
transfer agent, American Stock Transfer & Trust, paid all distributions as
declared. Continue to contact the Partnership for questions on distributions for
previous periods.
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After dissolution of the Partnership, distributions to each Unitholder of
record (whether an assignee or Limited Partner) will be made in accordance with
the Partnership Agreement.
Hugoton Nominee, Inc., a Texas nominee corporation ("Nominee"), was formed
in August 1982 on behalf of the Partnership and has agreed to act as the Limited
Partner of record for those Unitholders of record who do not become Substituted
Limited Partners. If Nominee receives notice of any action requiring the vote of
Limited Partners, it will provide or cause to be provided such notice to the
Unitholders of record representing Units for which Nominee is acting as the
Limited Partner of record and inform those holders of their rights to become
Substituted Limited Partners. The Partnership is required to reimburse Nominee
for all expenses incurred in such capacity ($343 for 1996 and $408 for 1995) and
shall indemnify it against certain liabilities incurred by Nominee in such
capacity. Nominee may at any time resign or be removed by the Partnership, and a
successor appointed.
The following summary is subject to the detailed provisions of the
Depositary Agreement and is qualified by reference to the Depositary Agreement,
copies of which are available at the Partnership's office and the Depositary.
The Depositary may at any time resign or be removed by the Partnership, and
a qualified successor appointed. Any Corporation into or with which the
Depositary may be merged or consolidated shall be the successor of the
Depositary without the execution or filing of any document or any further act.
Any provision of the Depositary Agreement, including the form of Depositary
Receipt, may at any time and from time to time be amended by agreement between
the Partnership and the Depositary in any respect deemed necessary or desirable
by them that does not adversely affect any substantial right of the Unitholders
of record. The Unitholders of record representing twenty five percent (25%) or
more of the deposited Units may at any time propose an amendment or amendments
to the Depositary Agreement. Any amendment of the Depositary Agreement that
imposes any fee, tax, or charge (other than fees and charges provided for in the
Depositary Agreement) upon, or otherwise adversely affects any substantial
rights of Unitholders of record shall not be effective until the expiration of
thirty (30) days after notice of the amendment has been given to the Unitholders
of record or, if the amendment is presented for a vote of the Unitholders of
record, until it has been approved by the affirmative vote of the Unitholders of
record representing fifty percent (50%) or more of the deposited Units. For the
purpose of considering any amendment of the Depositary Agreement that adversely
affects any substantial right of the Unitholders of record or any amendment
proposed by Unitholders of record but not adopted by the Depositary and the
Partnership, the Partnership shall call a meeting of Unitholders of record to be
held at a place in Dallas, Texas designated by the Partnership. The call shall
set forth the time, place, and purpose of the meeting, and notice thereof shall
be mailed at least twenty (20) days before the meeting to each record holder at
the close of business on the record date selected by the Partnership for the
purpose of the meeting. Any record holder may waive such notice. At the meeting
each record holder shall have one vote for each deposited Unit evidenced by each
Depositary Receipt registered in his name and may cast such vote in person or by
proxy. At the meeting the presence in person or by proxy of Unitholders of
record evidencing at least fifty percent (50%) of the deposited Units shall be
necessary to constitute a quorum. If a proposed amendment is approved by the
Unitholders of record representing fifty percent (50%) or more of the deposited
Units and if, in the case of an amendment that alters the duties or liabilities
of the Depositary, the Partnership or any General Partner thereof, it is
approved in writing by whichever of them is or are affected, the amendment shall
be declared adopted, and upon filing with the Depositary of a certificate of the
proceedings of the meeting, verified by the chairman and the secretary thereof,
together with any such approval, the amendment shall thereupon become effective.
In lieu of adoption at a meeting, an amendment of the Depositary Agreement may
be approved if Unitholders of record as of a record date selected by the
Partnership representing fifty percent (50%) or more of the deposited Units
consent thereto in writing filed with the Depositary. No amendment shall impair
the right of the Unitholders of record to surrender the Depositary Receipt and
withdraw any or all of the deposited Units evidenced thereby. Unitholders of
record will not be entitled to notice as Limited Partners or the
7
<PAGE> 10
right to vote as Limited Partners under the Depositary Agreement unless they are
Substituted Limited Partners (see notice requirements of Nominee above).
The Depositary shall terminate the Depositary Agreement whenever directed
to do so by the Partnership by mailing notice of termination to the Unitholders
of record then outstanding at least thirty (30) days before the date fixed for
the termination in such notice.
In addition to acting as depositary for the Units, the Depositary will act
as registrar and transfer agent for the Depositary Receipts. In addition to
receiving a monthly fee from the Partnership for serving in such capacities, the
Depositary will charge fees for Depositary Receipt transfers comparable to those
customary for stock transfer fees. All Depositary fees for transfer of
Depositary Receipts and withdrawal of Units will be borne by the Partnership and
not the Unitholders (except for fees customarily paid by stockholders for surety
bond premiums to replace lost or stolen certificates, special charges for
services requested by Unitholders and other similar fees or charges which will
be borne by the affected Unitholders). The Partnership will indemnify the
Depositary against certain liabilities incurred by the Depositary in connection
with its activities as depositary, transfer agent and registrar, including
liabilities arising under the Securities Act of 1933.
The Depositary may terminate the Depositary Agreement if, after the
Depositary has delivered to the Partnership a written notice of its election to
resign, sixty (60) days have elapsed and a successor Depositary has not accepted
its appointment. The Depositary shall mail notice of termination to the
Unitholders of record. Termination shall be effective on the date fixed in the
notice, which shall be at least thirty (30) days after it is mailed.
PRINCIPAL HOLDERS
The following table sets forth certain information regarding the beneficial
ownership of Units by the General Partners, their officers, and the
Partnership's officer effective as of January 1, 1997 and other persons,
excluding depositaries, of record on January 1, 1997 who held 5% or more of the
Units.
<TABLE>
<CAPTION>
NUMBER OF
UNITS PERCENT OF
BENEFICIALLY OWNED CLASS(1)(3)
------------------ -----------
<S> <C> <C>
P. A. Peak, Inc., General Partner.................... -- --
Preston A. Peak, President of P.A. Peak, Inc......... 1,577,412(2) 14.68%
James E. Raley, Inc., General Partner................ -- --
James E. Raley, President of James E. Raley, Inc..... 14,434 .13%
Wood Island Associates, Inc.......................... 683,590 6.36%
</TABLE>
- ---------------
(1) Based on 10,744,380 Units.
(2) Includes 1,576,412 Units owned by various entities for the benefit of Mr.
Peak and his family, and 1,000 Units owned by Hugoton Nominee, Inc. of which
he is the President and sole Director.
(3) The Units owned by the Advisory Committee members and the non-general
partner officer of the Partnership is less than 1% of the total Units
outstanding at December 31, 1996.
THE PARTNERSHIP
The following summary contains certain provisions of the Partnership
Agreement. The Partnership was formed pursuant to the TRLPA to own, hold,
explore, develop and operate the properties contributed to at its formation and
any other properties acquired pursuant to the Partnership Agreement.
The Partnership Agreement was amended August 9, 1995 to provide for an
Advisory Committee and to make certain other amendments which were necessary to
conform to, or to provide desired flexibility permitted by, changes in Texas
partnership law and federal tax law. The amendments were filed with the June 30,
1995 United States Securities and Exchange Commission Form 10-Q.
8
<PAGE> 11
The statements herein relating to the Partnership Agreement are summaries
and do not purport to be complete. The summaries make use of terms defined in
the Partnership Agreement and are qualified in their entirety by reference to
the Partnership Agreement, a copy of which is available at the Partnership's
office.
MANAGEMENT OF THE PARTNERSHIP
The General Partners, who have purchased an aggregate 1% net profits
interest in the Partnership, are P. A. Peak, Inc. whose sole shareholder is
Preston A. Peak, age 74, Investor, and James E. Raley, Inc., whose sole
shareholder is James E. Raley, age 57, Engineer. Kathleen A. Rawlings, age 39,
is the Partnership's Principal Accounting Officer and Administrative Services
Manager. She has been a full-time employee of the Partnership since 1983. Mr.
Peak is a former member of the Board of Directors of Kaneb Services, Inc. as
well as one of its subsidiaries. Mr. Raley is an independent consulting
engineer.
The Partnership established an Advisory Committee consisting of two
independent advisors in August, 1995 to function as the Partnership's audit
committee and to review and approve any transactions between the Partnership and
its General Partners, including any compensation and benefits paid to the
General Partners by the Partnership. Mr. Rawles Fulgham of Dallas, Texas and Mr.
W. Randall Blank of Houston, Texas presently serve on the Advisory Committee.
Prior to his retirement, Mr. Fulgham was Executive Director of Merrill Lynch
Private Capital, Inc. He presently serves as senior advisor of Merrill Lynch &
Co. Inc. and a director of Dresser Industries, Inc., NCH Corporation, Global
Industrial Technologies, Inc., and Banctec, Inc. Mr. Blank is Executive Vice
President of Rockland Pipeline Company in Houston, Texas and also serves on the
Board of Directors of the Gas Processors' Association.
The General Partners have complete and exclusive discretion in the
management and control of the business of the Partnership and all of its assets,
including authority to purchase or otherwise acquire any lease or other interest
in oil or gas property located within the geographical areas covered by the
properties conveyed to the Partnership and such other geographical areas within
the Hugoton Embayment as the General Partners may designate from time to time,
to borrow monies for the business of the Partnership, and to mortgage or pledge
all or any part of the Partnership's property as security, to surrender, release
or abandon any Partnership property, with or without consideration therefor, and
generally to execute and deliver such other documents and perform such other
acts as the General Partners in their sole discretion may determine to be
necessary or appropriate to carry out the business and affairs of the
Partnership.
Under the Partnership Agreement, each General Partner is entitled to
receive reasonable compensation for services rendered in operating and managing
the Partnership. The agreement, as amended effective January 1, 1995 and August
9, 1995 provides for a management fee to be divided among the General Partners
in an annual aggregate amount of $250,000 (previously $150,000 effective January
1, 1991) plus 1% of the annual gross income of the Partnership from the
Partnership properties. These amounts, on an accrual basis, are included in the
heading All Other Compensation within the following table (no salaries, bonuses
or other annual compensation was paid or accrued):
<TABLE>
<CAPTION>
ALL OTHER COMPENSATION
----------------------------------------------------------
PRESTON A. PEAK OR JAMES E. RALEY OR
SUMMARY COMPENSATION TABLE P.A. PEAK, INC. JAMES E. RALEY, INC.
YEAR GENERAL PARTNER GENERAL PARTNER TOTAL FOR YEAR
---- ------------------ -------------------- --------------
<S> <C> <C> <C>
1994.................................... $133,120 $139,425(a) $272,545
1995.................................... 178,468 202,278(a) $380,746
1996.................................... 132,064 283,958(a) $416,022
</TABLE>
- ---------------
(a) Includes the amount of taxable medical insurance premiums and payments of
$6,305, $5,894, and $5,560 for James E. Raley in 1994, 1995, and 1996,
respectively.
9
<PAGE> 12
Amounts expended by the Partnership for expenses (including certain private
club dues and office and other expenses) reimbursed or expended on behalf of
employees and the General Partners are believed to constitute ordinary and
incidental business expenses and are paid by the Partnership to facilitate the
conduct of Partnership business by such employees and General Partners. The
Partnership has concluded that the aggregate amount, if any, of personal benefit
is neither significant nor unusual nor does it result in any material additional
expense (less than $50,000) to the Partnership. No employees or officers of the
corporate General Partners participate in the Partnership's simplified employee
pension plan. Fees and expenses paid to members of the Advisory Committee amount
to less than $30,000 annually.
Upon the resignation or other Withdrawal of a General Partner, the
remaining General Partners must select a Successor General Partner who is not an
affiliate of any General Partner and must notify the Unitholders and Limited
Partners (collectively referred to as the "Unitholders") of such selection. Such
Successor General Partner shall be accepted unless Unitholders holding more than
25% of the Units call a meeting and a majority in interest of the Unitholders
entitled to vote at such meeting disapprove the selection. So long as there is
more than one General Partner, the approval of a majority of the General
Partners is required to bind the Partnership, except as the General Partners may
from time to time delegate responsibility among themselves or to others.
The General Partners shall not permit the Partnership to do business in any
jurisdiction or political subdivision in which the General Partners and the
Partnership have not previously taken such steps as may be necessary to assure
for the Limited Partners substantially the same limited liability as is provided
for limited partners in limited partnerships formed under the TRLPA.
TRANSACTIONS WITH AFFILIATES
The Partnership Agreement specifically provides that an Affiliate of the
Partnership may enter into contracts with the Partnership as operator, seller or
purchaser of properties or services, or in other capacities, so long as the
transactions are fair and reasonable to the Partnership and the terms of any
contract or conveyance are no less favorable to the Partnership than those which
could be obtained from unrelated persons. However, the Partnership shall not
sell any part of an oil and gas mineral lease to an Affiliate without the prior
consent of a majority in interest of the Unitholders. All transactions between
the Partnership and its General Partners and/or their Affiliates will be
reviewed and approved by the Advisory Committee.
IMMUNITIES AND INDEMNITIES
The Partnership Agreement also provides that no General Partner, nor any
shareholder, director, officer, employee or agent of a General Partner, shall be
liable to the Partnership or to the Partners for losses sustained or liabilities
incurred as a result of any act or omission which such General Partner in good
faith reasonably believed to be in, or not opposed to, the best interests of the
Partnership, unless such act or omission constituted gross negligence, willful
or wanton misconduct or breach of such General Partner's fiduciary obligations
to the Unitholders. A General Partner may rely upon, and shall have no liability
to the other Partners or to the Partnership if he relied upon, the opinion of
the Partnership's independent public accountants with respect to any matter
relating to computations and determinations which affect allocations or
distributions. Each General Partner is indemnified by the Partnership as
follows:
(a) In any threatened, pending or completed action, suit or proceeding
to which a General Partner was or is a party by reason of the fact that it
is or was a General Partner of the Partnership (other than an action by or
in the right of the Partnership), involving an alleged cause of action,
arising out of the manner in which such General Partner conducted the
Partnership's business if, in the transaction giving rise to such action,
suit or proceeding, such General Partner acted in good faith and in a
manner such General Partner reasonably believed to be in, or not opposed
to, the best interests of the Partnership and such General Partner's
conduct in such transaction did
10
<PAGE> 13
not constitute gross negligence, willful or wanton misconduct or willful
breach of such General Partner's fiduciary obligations to the Unitholders.
(b) In any threatened, pending or completed action, suit or proceeding
by or in the right of the Partnership, to which a General Partner was or is
a party, or is threatened to be made a party, by reason of the fact that it
is or was a General Partner of the Partnership, involving an alleged cause
of action arising out of the manner in which such General Partner managed
the internal affairs of the Partnership as prescribed by the Agreement or
by the TRLPA, or both (but excluding the activities covered in (a) above),
if, in the transaction giving rise to such action, suit or proceeding, such
General Partner acted in good faith and in a manner such General Partner
reasonably believed to be in, or not opposed to, the best interests of the
Partnership, except that no indemnification shall be made in respect of any
claim, issue or matters as to which such General Partner shall have been
adjudged to be liable for gross negligence, willful or wanton misconduct or
breach of such General Partner's fiduciary obligations to the Unitholders,
unless and only to the extent that the court in which such action, suit or
proceeding was brought shall determine upon application that, despite the
adjudication of liability but in view of all circumstances of the case,
such General Partner is fairly and reasonably entitled to indemnity for
such expenses which such court shall deem proper.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to a General Partner pursuant to the foregoing
provisions, the Partnership has been informed that in the opinion of the United
States Securities and Exchange Commission such indemnification is against public
policy as expressed in the Act and is therefore unenforceable.
The General Partners are reimbursed for all expenses incurred by them on
behalf of the Partnership, including their general and administrative expenses
(a total of $25,762 for 1996).
ACTIONS BY UNITHOLDERS
A majority in interest of the Unitholders shall have the right to waive any
restriction on the General Partners contained in the Partnership Agreement. The
Applicable Percentage Interest of the Unitholders (effective June 16, 1988,
defined as Unitholders who own 80% of all Units) shall have the right to
dissolve the Partnership, to amend the Partnership Agreement, to approve or
reject the sale of all or substantially all of the Partnership Property in the
event that the General Partners do not approve or recommend such sale, or to
remove one or all of the General Partners and elect a successor General Partner
to operate and carry on the business of the Partnership, subject in each case to
receipt of an opinion of counsel for the Unitholders or a ruling from the
Internal Revenue Service that the taking of such action will not affect the
federal income tax status of the Partnership, and subject further in the case of
the removal and replacement of a General Partner, to the following:
(a) The partnership interest of each removed General Partner must be
terminated by agreement between such terminating Partner and the successor
General Partner or, in the absence of an agreement, in accordance with the
following: The assets of the Partnership shall be valued, and gain or loss
allocated, as if all assets were sold for their fair market value as
determined by independent consulting engineers. Then, within 30 days after
such valuation is completed, the successor General Partner shall pay for
the Partnership interest of each removed General Partner cash equal to the
capital account balance of such Partner, after adjustment for the valuation
and allocation provided above, plus interest at a rate equal to the lower
of (i) the prime rate of Bank One, Texas, NA or (ii) the highest rate
permitted by law, for a period from the valuation date until the payment
date. The Partnership interest of each terminating Partner, including
income and deductions attributable thereto realized after the valuation
date, shall be owned by the successor General Partner.
(b) The successor General Partner must make arrangements, satisfactory
to the removed General Partner, to release the removed General Partner from
personal liability with respect to all
11
<PAGE> 14
Partnership liabilities, if any, or to provide the removed General Partner
with indemnity satisfactory to it against all liabilities of the
Partnership with respect to which such release is not obtained.
Meetings of the Unitholders may be called by any General Partner and shall
be called by the General Partners within 15 days following the written request
of Unitholders holding more than 50% of the Units on not less than 30 days nor
more than 60 days notice and at a reasonable time and place. Any action which
may be taken at a meeting of the Unitholders may be taken without a meeting if a
consent in writing, setting forth the action so taken, shall be signed by
Unitholders owning not less than the minimum percentage of Units that would be
necessary to authorize or take such action at a meeting at which all Unitholders
were present and voted. For purposes of obtaining a written consent, a General
Partner may require response by a specified date not later than 30 days after
the date any proposal is submitted to the Unitholders. Any Unitholder failing to
notify the Partnership of his support for or opposition to the proposal within
the specified time shall be conclusively deemed to have opposed the proposal.
No Unitholder shall have any right, power or authority to take part in the
management or control of the business of, or to transact any business for, the
Partnership. All management responsibility is vested in the General Partners.
Each Unitholder irrevocably constitutes and appoints the General Partners, and
each of them, his true and lawful attorney-in-fact and agent, to execute,
acknowledge, verify, swear to, deliver, record and file, in the Unitholder's
place and stead, all instruments, documents, and certificates which may be
required, from time to time, by the laws of the United States of America, the
State of Texas, and any other state or country in which the Partnership conducts
business to effectuate, implement and continue the valid existence of the
Partnership. This power of attorney is coupled with an interest, and shall be
irrevocable, shall survive the death, dissolution, bankruptcy, incompetency or
legal disability, of a Unitholder and shall extend to each Unitholder's heirs,
successors and assigns and may be exercised for all Unitholders (or any of them)
by listing all (or any) of the Unitholders required to execute any instrument.
No Limited Partner shall be required to make any additional contributions
to the Partnership. If additional funds are required, the General Partners will
attempt to obtain non-recourse loans but shall not be obligated to seek recourse
loans if non-recourse loans are not available. If any General Partner loans any
funds to the Partnership, the amount thereof shall be treated as a personal debt
of the Partnership, and shall bear interest at the prime rate set by Bank One,
Texas, NA.
There were no meetings of the Unitholders held during 1996.
ACCOUNTING AND ALLOCATIONS
For federal income tax purposes, income, gain, loss, deductions and federal
tax credits shall be allocated on a monthly basis to the partners in accordance
with their profit sharing percentages. The General Partners have the right to
make or decline to make all elections required or permitted to be made for
federal income tax purposes, including the Section 754 election, and such
elections, other than the Section 754 election, shall also be controlling for
book purposes. The classification, realization and recognition of income,
deductions and other items shall be consistent with their treatment for federal
income tax purposes applicable to a partnership electing the method of
accounting which the General Partners elect and the elections provided for
above, other than the Section 754 election. The Partnership Agreement requires
that within two and one-half months after the end of each fiscal year, the
General Partners must furnish to each Unitholder a statement containing
necessary information concerning the Partnership's operations for the preceding
fiscal year.
TRANSFERS
The Partnership interest of a General Partner may be transferred, in whole
or in part, only with the consent of the other General Partners, except where
such transfer is by reason of merger of a
12
<PAGE> 15
transferor corporate General Partner into another corporation, or other
transaction constituting a reorganization under Section 368 of the Internal
Revenue Code. As discussed above, the Partnership Agreement contains provisions
for valuing the Partnership interest of a General Partner. A Unitholder may
transfer all or part of his Units to any person or persons; provided, however,
that such transfer shall not confer upon the transferee any right to become a
Substituted Limited Partner. A transferee of all or a part of such Units held
prior thereto by a Unitholder may be admitted to the Partnership as a
Substituted Limited Partner only if the transferee had requested and received
the permission of the General Partners, which permission may be withheld in the
sole discretion of the General Partners. Unless and until a transferee becomes a
Substituted Limited Partner, the transferee's status and rights shall be limited
to the rights of a transferee of limited partnership interests under the TRLPA.
To the extent required by applicable law, if a transferee is not an Eligible
Citizen, a Depositary Receipt evidencing the transferred Units will be issued
and delivered to him, but he shall not be entitled to admission as a Substituted
Limited Partner and shall remain a non-citizen assignee until he transfers the
Units or he becomes an Eligible Citizen and elects to become a Substituted
Limited Partner. An Eligible Citizen means a citizen or national of the United
States; an alien lawfully admitted for permanent residence in the United States;
a private, public or municipal corporation organized under the laws of the
United States or of any State or of the District of Columbia, or a territory
thereof; or an association of such citizens, nationals, resident aliens, or
private, public or municipal corporations, States or political subdivisions of
States. If at any time the Partnership or a General Partner is named a party in
any judicial or administrative proceeding that seeks the cancellation or
forfeiture or any property in which the Partnership has an interest because of
the nationality (or any other status that subjects the Partnership to the risk
of losing its eligibility to acquire or hold oil and gas leasehold interests in
federal lands) of any one or more Unitholders the General Partners may redeem
the partnership interest of such Unitholder.
DISSOLUTION AND LIQUIDATION
The Partnership shall be dissolved upon the first to occur of the following
events:
(a) The failure of the Partnership to own any oil and gas properties.
(b) The Withdrawal of a General Partner, which is defined as the
death, dissolution, resignation, insanity or other incapacity of a General
Partner, termination of a marital relationship in which all or a part of
the record or beneficial ownership of the General Partner is transferred,
certain bankruptcy acts of a General Partner or a purported transfer by a
General Partner of his management rights in the Partnership (subject to
reconstitution as referred to below).
(c) The agreement of the Applicable Percentage Interest of the
Unitholders.
(d) The agreement of all General Partners.
(e) December 31, 2050.
The dissolution shall be effective on the day the event occurs giving rise
to the dissolution, but the Partnership shall not terminate until all its
affairs have been wound up and its assets distributed. If the Partnership
dissolves because of the Withdrawal of a General Partner, the Partnership shall
not liquidate, but shall be reconstituted and shall continue as it was before.
In liquidation, the assets of the Partnership shall be applied in the
following order or priority:
(a) First, there shall be paid all liabilities of the Partnership to
creditors other than Partners and Unitholders (collectively referred to as
the "Partners"). If any liability is contingent, or uncertain in amount, a
reserve equal to the maximum amount to which the Partnership could be
reasonably held liable will be established. Upon the satisfaction or other
discharge of such
13
<PAGE> 16
contingency, the amount of the reserve not required, if any, will be
distributed in accordance with the balance of this provision.
(b) Second, the debts, if any, of the Partnership to the Partners
shall be paid.
(c) Third, to the Partners in an amount equal to their then existing
Capital Accounts. If any General Partner's Capital Account is less than
zero, then each such Partner shall contribute cash to the Partnership equal
to such deficit.
(d) Fourth, to the Partners in accordance with their Profit Sharing
Percentages.
Each Partner agrees with every other Partner that (i) any Partner and any
person affiliated with a Partner may engage in or possess any interest in
another business venture or ventures; (ii) neither the Partnership nor the other
Partners shall have any right in said independent venture or to the income or
profits derived therefrom; and (iii) any General Partner may organize and be a
General Partner in other limited partnerships organized for the exploration for
oil, gas and other minerals or for any other purpose.
AMENDMENTS
Amendments to the Partnership Agreement may be proposed by any General
Partner, or by Unitholders owning not less than 50% of the Units and must be
approved by the Applicable Percentage Interest of the Limited Partners. However,
no amendment shall be made which would cause the Partnership to be classified as
a corporation for purposes of the Internal Revenue Code. Without notice to the
Unitholders, the General Partners may make amendments to the Partnership
Agreement which do not adversely affect the rights of the Unitholders in any
material respect.
INHERITANCE TAXES
Under certain circumstances, Texas inheritance tax and other laws regarding
devolution, probate and administration may be applicable to property in Texas,
including intangible personal property, of both resident and nonresident
decedents. Insofar as the Depositary Receipts may represent or constitute an
interest in property in Kansas and Oklahoma, they may be subject to devolution,
probate and administrative laws, and inheritance, gift and similar taxes, under
the laws of such states.
INCOME TAX TREATMENT
Dorchester Gas Corporation received the opinion of counsel that the
Partnership would be classified as a partnership and that the Unitholders would
be treated as limited partners for federal income tax purposes. AS A NATURAL
RESOURCES PARTNERSHIP, THE PARTNERSHIP WILL NOT BE AFFECTED BY EXISTING TAX
PROVISIONS THAT WILL CAUSE CERTAIN PUBLICLY TRADED PARTNERSHIPS TO BE TAXED AS
CORPORATIONS IN 1998. The Partnership itself, to the extent that it is treated
for federal income tax purposes as a partnership, is not subject to any federal
income taxation, but it is required to file annual partnership returns of
income. Each Unitholder will be required to take into account in computing his
federal income tax liability his distributive share (determined in accordance
with the allocation of profits and losses set forth in the Partnership
Agreement) of all items of Partnership income, gain, loss, deduction or credit
for any taxable year of the Partnership ending within or with his taxable year
without regard to whether such Unitholder has received or will receive any cash
distributions from the Partnership. The profits and losses of the Partnership
are allocated 1% to the General Partners and 99% to the Limited Partners.
Therefore, the items of income, gain, loss, deduction or credit will be
allocated 1% to the General Partners and 99% to the Unitholders. The Partnership
is a "federally registered partnership" pursuant to the provisions of the
Internal Revenue Code. As such the IRS may assess a deficiency attributable to
Partnership items within four years (instead of the normal three-year period)
after the Partnership return is filed. The applicable period of limitation with
respect to Partnership items may be extended for all Unitholders by the General
Partners.
14
<PAGE> 17
A Unitholder's distributive share of the taxable income or loss of the
Partnership generally will be required to be included in determining his
reportable income for state or local tax purposes in the jurisdiction in which
he is a domicile or resident. In addition, the Partnership will conduct
operations in some states, including Kansas and Oklahoma, which impose a tax on
a Unitholder's share of the income derived from the activities or properties of
the Partnership in that state whether or not the Unitholder is a resident or
domicile of such state. Accordingly, a Unitholder may be subject to taxes in a
state in which the Partnership has operations or properties in addition to the
state in which the Unitholder has his residence or domicile. The Partnership
initiated an agreement with the Kansas Department of Revenue removing the
reporting burden for partners who are nonresidents of Kansas and satisfying any
tax liability that might exist with respect to their allocable share of
Partnership income attributable to Kansas for 1982 through 1996.
In view of the complexities of the tax considerations involved in the
ownership of Depositary Receipts, the holders of such are urged to consult tax
or legal advisors to determine how and to what extent such holders will be taxed
for federal and state income tax purposes and to determine all other legal
consequences to such holders of that status (See Note 1 to the Financial
Statements).
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
SELECTED FINANCIAL DATA
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995, 1994, 1993, AND 1992
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Net operating revenues.................. $17,055 $13,027 $11,624 $14,454 $ 5,038
Net earnings............................ $ 7,830 $ 7,592 $ 7,599 $ 9,687 $ 1,997
Net earnings per Unit................... 72c 70c 70c 89c 18c
Cash distributions per Unit............. 68c 68c 68c 61c 23c
Total assets at December 31............. $22,683 $19,601 $18,861 $16,716 $12,013
Notes payable -- long term.............. $ 3,144 $ 1,725 $ 1,850 -- --
Partnership capital at December 31...... $15,389 $14,499 $13,769 $13,643 $10,653
</TABLE>
15
<PAGE> 18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As announced August 2, 1996, all of the Partnership's outstanding
litigation, claims, and counterclaims with Parker & Parsley Petroleum Company
entities have been settled. In connection with the settlement, the Partnership
paid Parker & Parsley $7 million at the settlement closing on August 14, 1996,
and the Partnership will pay Parker & Parsley, prospectively only, a production
payment (overriding royalty -- "ORRI") that was created in the 1986 acquisition
by the Partnership of 20% of the Oklahoma wells. The amount of such annual
production payment is based upon the difference between market gas prices
compared to a table of rising prices and based upon a table of declining
volumes. The first production payment to be paid in 1997 is estimated to be
$1,035,000. Accruals for the production payment have reduced net earnings
$760,000 through December 31, 1996. Additionally, the settlement resulted in a
September 1, 1996 exchange of wells in Kansas by which the Partnership
transferred to Parker & Parsley a non-operated interest in 14 wells and received
from Parker & Parsley their interest in 18 wells operated by the Partnership.
Consequently, the Partnership increased ownership from 80% to 100% of the
working interest in 18 wells.
The litigation settlement impacted the 1996 financial statements with
one-time charges as follows: a $4,263,000 charge to earnings, a $200,000
reduction of liabilities, and a $3,025,000 increase in natural gas properties.
These amounts represent the cash payment of $7,000,000 along with additional
costs such as royalty payments and legal fees. Along with the prospective
production payment previously mentioned, these adjustments represent all known
significant provisions for the settlement.
The 1996 operating expenses include a charge of $395,000 for Kansas tax
reimbursements (including related interest through December 31, 1996) received
by the Partnership during the years 1983 to 1987. This charge results from a
ruling by the United States Court of Appeals for the District of Columbia which
overruled a previous order by the Federal Energy Regulatory Commission. The
Partnership, as well as numerous other parties, may pursue further judicial
review or regulatory relief with respect to this matter.
Earnings for 1996 after reflecting the settlement and the provision for a
possible return of approximately $395,000 of Kansas ad valorem tax
reimbursements, were $7,830,000 or $0.72 per unit. Absent the one-time charges
in litigation settlement and the Kansas ad valorem tax provision, the
Partnership's earnings would have been approximately $12,488,000 or $1.15 per
unit.
The Partnership's settlement removes any uncertainties regarding the
operational status of its natural gas properties, its ability to transport its
Oklahoma gas to market, as well as its ability to obtain a market responsive
price for all of its natural gas. Consequently, the Partnership has canceled its
previously announced plans to build a new $7 million pipeline gathering system
in Oklahoma.
Net cash flows from operating activities during 1996 including settlement
expenditures were $10,291,000, compared to $9,104,000 during 1995. Operating
cash flows were positively impacted in 1996 by natural gas market prices which
were significantly higher compared to 1995.
Absent one-time special charges, as in 1996, the Partnership's year to year
changes in net earnings and cash flows from operating activities are principally
determined by changes in either natural gas sales volumes or gas prices. Net
earnings and cash flows between 1994 and 1995 were favorably impacted by
increased gas sales since gas production was not reduced as during 1994 for
construction of the Partnership's new Oklahoma compression facilities.
Conversely, 1995 prices were 8% less than 1994 which caused a greater negative
impact than a 27% increase in operating expenses resulting from start-up of the
gas gathering and compression operations. Future increases in operating costs
and expenses are not expected to be as significant since the personnel and
equipment needed to operate its Oklahoma facilities are now in place. For
example, 1996 operating expenses would have been lower than 1995 if not for the
$395,000 Kansas ad valorem provision. Accounts receivable turnover has improved
during 1996.
16
<PAGE> 19
The Partnership's new 5,400 horsepower gas compression and dehydration
facility in Oklahoma, which was constructed at a cost of approximately $6
million, has continued to operate essentially trouble free since its start-up in
November, 1994. Electronic measurement was installed on the Oklahoma gas
gathering pipelines during 1996. Total field operation employees increased from
four to the current eight during 1994. This increase in personnel is reflective
of the Partnership's greater operational responsibility in both compression and
gas gathering pipeline operations. Field usage consumption of natural gas at the
compression and dehydration facilities is estimated to be approximately 4% of
the inlet gas volume. The Partnership anticipates gradual increases in field
operating costs and expenses as repairs to its 45-year-old pipelines and gas
wells become more frequent. The Partnership does not anticipate significant
replacement of these items at this time.
In order to supplement its cash flows from operating activities and finance
significant capital projects, the Partnership entered into a $15 million
long-term unsecured revolving credit facility (the "Credit Agreement") with Bank
One, Texas, NA in 1994. See Note 2 to the Partnership's Financial Statements for
additional information on the Credit Agreement. The Partnership does not believe
that changes in interest rates will have a material effect on its financial
condition or operating results.
Cash flows from operating activities remain sufficient to meet the
Partnership's anticipated costs and expenses and debt service requirements. The
Partnership has no current outstanding material commitments for capital
expenditures.
The Partnership's portion of gas sales volumes (in MMCF) not reduced for
Oklahoma production payment, and weighted average BTU adjusted sales prices per
MCF were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------
1996 1995 1994
----- ----- -----
<S> <C> <C> <C>
Sales Volumes:
Oklahoma.............................. 6,250 6,467 4,899
Kansas................................ 2,202 2,017 2,135
----- ----- -----
Total......................... 8,452 8,484 7,034
===== ===== =====
Weighted Average Sales Prices:
Oklahoma.............................. $2.24 $1.54 $1.60
Kansas................................ 2.22 1.46 1.76
Overall weighted average.............. 2.24 1.52 1.65
</TABLE>
Oklahoma 1996 sales volumes were slightly less than volumes in 1995
reflecting, in part, normal depletion. Oklahoma sales volumes in 1994 were
significantly reduced beginning in May, 1994 and continuing through October,
1994 during which time the Partnership was limited to delivering its gas to low
pressure pipelines while the Oklahoma compression facility was under
construction. During 1996, the Partnership drilled and completed two replacement
wells in Oklahoma.
Kansas 1996 sales volumes were higher than 1995 volumes partly as a result
of completion in January 1996 of modifications of the gas compression facilities
and extension of the gas gathering pipelines. However, the Partnership and other
producers in our area have experienced continued declines in Kansas gas
reservoir pressures. Such pressure declines could result in future compression
and/or gas gathering pipeline modifications. Prior to September 1, 1996 Kansas
volumes in the above table reflect the Partnership's portion of 80% working
interest in 18 wells operated by the Partnership and 32% working interest in 14
non-operated wells. After September 1, 1996, the Kansas volumes are from wells
in which the Partnership owns 100% working interest. The change in working
interest ownership had a negligible effect on the Partnership's portion of
Kansas gas sales and reserves. During 1995 and 1996 the Partnership drilled and
completed two additional infill wells in Kansas.
Depreciation, depletion and amortization costs (collectively, "DD&A") in
1995 increased significantly compared to 1994 primarily as a result of the
addition of the $6 million Oklahoma compression facility. While dependent upon a
holder's original tax basis in the Partnership, as well as various other
17
<PAGE> 20
factors, the Partnership anticipates that the 1996 litigation settlement costs
and increased tax depletion and depreciation deductions resulting from property
additions during 1996 will tend to offset increased taxable revenues resulting
from higher gas prices in 1996. Financial reporting for SEC purposes will not
necessarily reflect taxable income as reported on Unitholder Form K-1s.
The Partnership is pleased to have resolved its litigation and expects
recent favorable winter gas prices to accelerate the ability to reduce debt. As
discussed in Business and Properties of the Partnership -- Oklahoma Properties,
the Partnership is preparing to begin evaluating the potential of the Fort Riley
zone. Also, as discussed in Business and Properties of the
Partnership -- Regulations and Prices, the Partnership is active in supporting
its views regarding possible Oklahoma regulatory/legislative action on rules
regulating gas production quantities and on infill drilling. Both infill
drilling and elimination of field rules could require considerable capital
expenditures. THE OUTCOME AND THE COST OF SUCH ACTIVITIES IS UNPREDICTABLE.
While the Partnership has not repurchased and retired any Units to date, that
program is still in place.
18
<PAGE> 21
FINANCIAL INFORMATION
Financial Statements:
Statements of Earnings for the Years Ended December 31, 1996, 1995, 1994.
Balance Sheets as of December 31, 1996 and 1995.
Statements of Changes in Partnership Capital for the Years Ended
December 31, 1994, 1995 and 1996.
Statements of Cash Flows for the Years Ended December 31, 1996, 1995, 1994.
Notes to Financial Statements.
Exhibits:
<TABLE>
<S> <C>
3. -- Amended and Restated Certificate and Agreement of Limited Partnership, as amended*
4.1 -- Depositary Agreement, as amended*
4.2 -- Specimen Depositary Receipt**
4.3 -- Nominee Agreement among the Partnership, Dorchester and Nominee**
27. -- Financial Data Schedule
</TABLE>
All other schedules and exhibits have been omitted because they are either
not required, not applicable or the required information is disclosed in the
Financial Statements or related Notes. No reports on Form 8-K were filed during
the last quarter of the year covered by this report.
- ---------------
* Previously filed and incorporated by reference to the respective Exhibits
(bearing the same exhibit numbers) to the Partnership's Form 10-Q for the
quarter ended June 30, 1995.
** Previously filed and incorporated by reference to the respective Exhibits
(bearing the same exhibit numbers) to the Partnership's Form 10-K for the
year ended December 31, 1995.
REPORT OF INDEPENDENT ACCOUNTANTS
To the General Partners and Unitholders of Dorchester Hugoton, Ltd.:
We have audited the financial statements of Dorchester Hugoton, Ltd. listed
under Financial Information above of this Form 10-K. These financial statements
are the responsibility of the Partnership's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Dorchester Hugoton, Ltd. as of
December 31, 1996 and 1995, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996 in conformity
with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Dallas, Texas
February 11, 1997
19
<PAGE> 22
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
STATEMENTS OF EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Net operating revenues:
Natural gas sales......................................... $18,904 $12,903 $11,585
Other..................................................... 173 124 39
Production payment (ORRI)................................. (818) -- --
Litigation settlement adjustment.......................... (1,204) -- --
------- ------- -------
Total net operating revenues...................... 17,055 13,027 11,624
------- ------- -------
Costs and expenses:
Operating................................................. 2,423 2,218 1,747
Production taxes.......................................... 1,035 831 814
Depreciation, depletion and amortization.................. 1,548 1,362 810
General and administrative:
Tax and regulatory reporting........................... 167 166 137
Depositary and transfer agent fees..................... 10 14 17
Other.................................................. 370 405 321
Management fees........................................... 410 375 266
Interest expense.......................................... 210 144 41
Litigation settlement expense............................. 3,039 -- --
Other expense (income).................................... 13 (80) (128)
------- ------- -------
Total costs and expenses.......................... 9,225 5,435 4,025
------- ------- -------
Net earnings................................................ $ 7,830 $ 7,592 $ 7,599
======= ======= =======
Net earnings per Unit....................................... 72c. 70c. 70c.
---- ---- ----
---- ---- ----
</TABLE>
See Notes to Financial Statements
20
<PAGE> 23
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
1996 1995
------- -------
<S> <C> <C>
Current assets:
Cash and temporary cash investments....................... $ 115 $ 183
Investments -- available for sale......................... 2,646 2,190
Accounts receivable....................................... 3,054 3,197
Prepaid expenses and other current assets................. 103 136
------- -------
Total current assets................................... 5,918 5,706
------- -------
Property and equipment -- at cost:
Natural gas properties (full cost method)................. 25,442 21,168
Other..................................................... 1,000 1,072
------- -------
Total................................................ 26,442 22,240
Less accumulated depreciation, depletion and amortization:
Full cost depletion....................................... 9,375 7,916
Other..................................................... 302 429
------- -------
Total................................................ 9,677 8,345
------- -------
Net property and equipment................................ 16,765 13,895
------- -------
Total assets......................................... $22,683 $19,601
======= =======
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
Accounts payable.......................................... $ 296 $ 776
Current portion of long-term debt......................... 47 25
Production and property taxes payable..................... 755 231
Royalties payable......................................... 1,199 297
Accrued liabilities -- other.............................. -- 200
Distributions payable to unitholders...................... 1,853 1,848
------- -------
Total current liabilities.............................. 4,150 3,377
Notes payable -- long-term.................................. 3,144 1,725
------- -------
Total liabilities...................................... 7,294 5,102
------- -------
Commitments and contingencies (Note 3)...................... -- --
Partnership capital:
General partners.......................................... 77 68
Unitholders............................................... 15,312 14,431
------- -------
Total partnership capital.............................. 15,389 14,499
------- -------
Total liabilities and partnership capital............ $22,683 $19,601
======= =======
</TABLE>
See Notes to Financial Statements
21
<PAGE> 24
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
GENERAL
PARTNERS UNITHOLDERS TOTAL
-------- ----------- ------
<S> <C> <C> <C>
Year Ended December 31, 1994:
Balance at December 31, 1993........................... $ 59 $13,584 $13,643
Net earnings.............................................. 76 7,523 7,599
---- ------- -------
Distributions:
Cash paid on April 15, July 15 and October 14, 1994
(17c. per Unit)...................................... (55) (5,480) (5,535)
Payable on January 20, 1995 to holders of record on
December 31, 1994 (17c. per Unit).................... (19) (1,826) (1,845)
---- ------- -------
Total distributions............................. (74) (7,306) (7,380)
---- ------- -------
Net unrealized holding loss on investments available for
sale................................................... (0) (66) (66)
Other..................................................... -- (27) (27)
---- ------- -------
Balance at December 31, 1994........................... 61 13,708 13,769
---- ------- -------
Year Ended December 31, 1995:
Net earnings.............................................. 76 7,516 7,592
---- ------- -------
Distributions:
Cash paid on April 21, July 21 and October 20, 1995
(17c. per Unit)...................................... (55) (5,480) (5,535)
Payable on January 19, 1996 to holders of record on
December 31, 1995 (17c. per Unit).................... (19) (1,826) (1,845)
---- ------- -------
Total distributions............................. (74) (7,306) (7,380)
---- ------- -------
Net unrealized holding gain on investments available for
sale................................................... 5 545 550
Other..................................................... -- (32) (32)
---- ------- -------
Balance at December 31, 1995........................... 68 14,431 14,499
---- ------- -------
Year Ended December 31, 1996:
Net earnings.............................................. 78 7,752 7,830
---- ------- -------
Distributions:
Cash paid on April 19, July 19 and October 18, 1996
(17c. per Unit)...................................... (55) (5,480) (5,535)
Payable on January 17, 1997 to holders of record on
December 31, 1996 (17c. per Unit).................... (19) (1,826) (1,845)
---- ------- -------
Total distributions............................. (74) (7,306) (7,380)
---- ------- -------
Net unrealized holding gain on investments available for
sale................................................... 5 450 455
Other..................................................... -- (15) (15)
---- ------- -------
Balance at December 31, 1996........................... $ 77 $15,312 $15,389
==== ======= =======
</TABLE>
See Notes to Financial Statements
22
<PAGE> 25
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995, 1994
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995 1994
------- ------ ------
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings.............................................. $ 7,830 $7,592 $7,599
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Depreciation, depletion and amortization............... 1,548 1,362 810
Loss on sale of property and equipment................. 7 12 26
Other.................................................. (15) (32) (27)
Changes in current assets and liabilities:
Accounts receivable.................................. 143 (56) 271
Prepaid expenses and other current assets............ 33 (49) 44
Accounts payable, taxes and royalties payable........ 945 275 127
Other accrued liabilities............................ (200) -- (100)
------- ------ ------
Net cash provided by operating activities................... 10,291 9,104 8,750
------- ------ ------
Cash flows from investing activities:
Capital expenditures, net of retirements.................. (4,361) (1,305) (6,260)
Purchase of available-for-sale securities................. -- -- (3)
Cash received on sale of property and equipment........... 24 29 10
------- ------ ------
Net cash used by investing activities....................... (4,337) (1,276) (6,253)
------- ------ ------
Cash flows from financing activities:
Proceeds from long-term borrowing......................... 13,700 9,200 1,800
Loan payments............................................. (12,347) (9,325) --
Other..................................................... -- (123) 123
Distributions paid to Unitholders......................... (7,375) (7,397) (7,386)
------- ------ ------
Net cash used by financing activities....................... (6,022) (7,645) (5,463)
------- ------ ------
Increase (decrease) in cash and temporary cash
investments............................................... (68) 183 (2,966)
Cash and temporary cash investments at beginning of year.... 183 -- 2,966
------- ------ ------
Cash and temporary cash investments at end of year.......... $ 115 $ 183 $ --
======= ====== ======
Supplemental cash flow and other information:
Interest paid (no interest was capitalized)............... $ 204 $ 142 $ 41
======= ====== ======
Distributions declared but not paid....................... $ 1,853 $1,848 $1,865
======= ====== ======
</TABLE>
See Notes to Financial Statements
23
<PAGE> 26
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Formation of Partnership -- Dorchester Hugoton, Ltd. (the "Partnership")
was formed June 16, 1982, by Dorchester Gas Corporation ("DGC") which conveyed
to the Partnership 80 percent of its working interest in certain natural gas
properties effective June 1, 1982. The properties contributed by DGC have been
recorded by the Partnership at the allocated historical net cost of the
properties to DGC based on the estimated relative fair value of the contributed
properties to DGC's total oil and gas properties located in the United States.
Basis of Presentation -- Per-Unit information is calculated by dividing the
99% interest owned by Unitholders by the 10,744,380 Units outstanding.
Reclassification -- Certain amounts in the 1994 financial statements have
been reclassified to conform with the 1995 and 1996 presentation.
Estimates -- The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents -- The Partnership's principal banking and
short-term investing activities are with major financial institutions. Short
term investments with a maturity of three months or less are considered to be
cash equivalents and are carried at cost, which approximates market value. Cash
balances in these accounts may, at times, exceed federally insured limits. The
Partnership has not experienced any losses in such cash accounts or investments
and does not believe it is exposed to any significant risk on cash and cash
equivalents.
Concentration of Credit Risks -- The Partnership sells its natural gas to
gas purchasers in the United States and performs on-going credit evaluations of
its customers, requiring major corporate guarantees or letters of credit on a
regular basis. The Partnership has incurred minimal credit losses.
Investments -- The Partnership's investments consist of 27,000 shares of
Exxon Corporation common stock purchased for $1,776,450 in 1993 and are
classified as available for sale. The Partnership has recognized an unrealized
holding gain on the increase in value of $455,625 and $550,125 in 1996 and 1995,
respectively, and an unrealized holding loss on the temporary decline in value
of $66,825 in 1994. These adjustments have been treated as a separate component
of the Partnership's capital. At December 31, 1996 and 1995, the carrying value
of this stock, based on the quoted market price, was $2,646,000 and $2,190,375,
respectively.
Property and Equipment -- The Partnership follows the full cost method of
accounting prescribed by the United States Securities and Exchange Commission
under which all costs relating to the acquisition, exploration and development
of natural gas properties (both productive and nonproductive) are capitalized
(not to exceed discounted future net cash flows) by the country (United States)
in which the costs are incurred. Natural gas properties are being depleted on
the unit-of-production method using proved gas reserves. Other assets are being
depreciated or amortized using straight-line methods for financial reporting
purposes over estimated useful lives of 3 to 40 years.
Gains or losses are recognized upon the disposition of natural gas
properties involving a significant portion of the Partnership's reserves.
Proceeds from other dispositions of natural gas properties are credited to the
full cost account. No gain or loss was recognized on the exchange of properties
with P&P in August, 1996.
24
<PAGE> 27
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
General Partners -- The Partnership's General Partners have the overall
responsibility for the management, operation and future development of the
properties. Each General Partner is entitled to receive reasonable compensation
in the form of a management fee, to be divided among the General Partners in an
annual aggregate amount of $250,000 effective January 1, 1995 (previously
$150,000 effective January 1, 1991) plus 1% of the gross income from the
Partnership properties for services rendered in operating and managing the
Partnership. The General Partners are also reimbursed for all general and
administrative expenses incurred by them on behalf of the Partnership.
Operating Agreement -- The Partnership operates substantially all of its
natural gas properties. Efforts are made to balance each working interest
owner's share of production to gas marketed by increasing or decreasing the
volumes of gas allocated to each working interest owner in subsequent months so
that each such working interest owner shall be able to share in the actual
cumulative production in proportion to its interest in the properties. The
Partnership receives in-kind the Partnership's share of gas produced from 11
wells in Oklahoma (10 operated by others and 1 operated by the Partnership). At
December 31, 1996, the net balance owed the Partnership is only approximately
4,000 MCF, down from 62,000 MCF and 110,000 MCF at December 31, 1995, and 1994,
respectively.
Other Agreements -- Until May 1, 1994 the Partnership's Oklahoma natural
gas was sold under a 1946 Gas Purchase Contract with Natural Gas Pipeline
Company of America and assigns after processing pursuant to a June 16, 1982 Gas
Processing Agreement with a Parker & Parsley Petroleum Company entity. Effective
May 1, 1996 the Partnership's Kansas gas was committed, based on market prices,
to NorAm Energy Services for one year and also committed for processing to Enron
Gas Processing Company for one year. During 1996, the Partnership's Oklahoma gas
began a five year commitment to Williams Field Services Company for delivery
through a processing facility. Sales of Oklahoma gas remain subject to monthly
agreements. The quantity sold is determined by nominations at the processing
facility outlet and imbalances with actual deliveries to Williams Field Services
Company are corrected in each subsequent month. At December 31, 1996 the
imbalance was 3,374 MMBtu owed by the Partnership.
Operating Revenue -- Natural gas revenues are recognized as production and
sales take place (the "sales method"). The Partnership's purchasers (including
their affiliates) who accounted for more than 10% of natural gas revenues for
each of the years ended December 31, 1996, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
PURCHASER PURCHASER PURCHASER PURCHASER PURCHASER
"A" "B" "C" "D" "E"
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
1996.................................. 77% 19%
1995.................................. 36% 55%
1994.................................. 20% 17% 28% 18%
</TABLE>
The Partnership believes that the loss of any single customer would not
have a material adverse effect on the results of its operations because the
transmission (and gathering) pipelines connected to the Partnership's facilities
are required by the Federal Energy Regulatory Commission or state regulations to
provide continued equal access for shipment of natural gas. Additionally, there
are numerous buyers available on each pipeline.
Income Taxes -- The Partnership is treated as a partnership for income tax
purposes and, as a result, income or loss of the Partnership is includible in
the tax returns of the individual Unitholders. Accordingly, no recognition has
been given to income taxes in the financial statements.
25
<PAGE> 28
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
An investment in the Partnership by certain tax-exempt entities (such as
IRA's, pension plans, etc.) may produce Unrelated Business Taxable Income
("UBTI"). Many tax-exempt entities are subject to tax on UBTI. Tax exempt
entities subject to the tax on UBTI must file with the IRS for each tax year
that the entity has gross income of $1,000 or more from an unrelated trade or
business. Additionally, the Partnership reports Unitholders' share of
depreciation adjustments for alternative minimum tax ("AMT") purposes. The AMT
adjustment must be taken into account when figuring Unitholder passive activity
gains and losses for AMT purposes. UBTI and AMT are specialized areas of the tax
law -- Unitholders should consult tax advisors concerning their own tax
situation. Finally, depletion of natural gas properties is an expense allowable
to each individual partner and the depletion expense as reported on the
financial statements will not be indicative of the depletion expense an
individual partner or Unitholder may be able to deduct for income tax purposes.
Simplified Employee Pension Plan -- Contributions aggregating $75,493,
$57,274, and $44,257, were made to eligible employees' accounts for 1996, 1995
and 1994, respectively under the Partnership's simplified employee pension plan.
Employees become eligible in their third calendar year of employment. The
Partnership does not have any other post-retirement benefit plans.
Operating Leases -- The Partnership rents administrative office space under
leases expiring at various dates through 2001.
Environmental Costs -- Expenditures for environmental related activities
are expensed or capitalized in accordance with generally accepted accounting
principles. Liabilities for these expenditures are recorded when it is probable
that obligations have been incurred and the amounts can be reasonably estimated.
2. LOANS AND LONG-TERM DEBT
On July 19, 1994, the Partnership entered into a $15,000,000 unsecured
revolving credit facility (the "Credit Agreement") with Bank One, Texas, NA (the
"Bank"). Effective August 12, 1996, the Credit Agreement was restated to
increase the borrowing base from $4,250,000 to $8,500,000, which will
subsequently be re-evaluated by the Bank at least semi-annually. If, on any such
date, the aggregate amount of outstanding loans and letters of credit exceed the
current borrowing base, the Partnership is required to repay the excess. This
credit facility includes both cash advances and any letters of credit that the
Partnership may need, with interest being charged at the Bank's base rate, which
was 8.25% on December 31, 1996. All amounts borrowed under this facility become
due and payable on July 31, 1999. As of December 31, 1996, a letter of credit
totaling $25,000 was issued under the credit facility and the amount borrowed
was $3,100,000. The Partnership is required to maintain certain minimum defined
financial ratios with respect to its current ratio and the ratio of net cash
flow to debt service. In addition, Partnership capital must be maintained above
specified amounts. This note has been guaranteed by the General Partners. Since
July 1994 the maximum amount borrowed under the Credit Agreement has been
$5,800,000. The 1996 and 1995 weighted average amounts borrowed under the Credit
Agreement was $2,200,000 and $1,400,000, respectively.
The Partnership purchased land in 1996 adjacent to its Kansas compression
and dehydration facility for $93,600, of which $66,450 is payable by contract at
$22,150 per year plus interest at 8.5% and is collateralized by the land. In
early January, 1997, the Partnership completed its obligation under a 1994
contract to purchase land at its Oklahoma compression facility. The final
payment was $25,000 plus interest at 6%. The remaining note approximates market
value.
26
<PAGE> 29
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
3. LITIGATION AND OTHER
On August 14, 1996 the Partnership paid Parker & Parsley Petroleum Company
entities (successor to Damson Oil Corporation and Dorchester Master Limited
Partnership -- collectively referred to as "P&P" or as "Parker & Parsley") $7
million in settlement of all outstanding litigation. Some of the numerous issues
resolved by this settlement include the withdrawal by P&P of its claims of gas
processing rights to the Partnership's Oklahoma gas production, its rights to
participate in any Oklahoma gas wells, and its claims for unpaid production
payment amounts. The Partnership will, prospectively only, pay P&P any
production payment (overriding royalty interest) amount that may be due as set
forth in a 1986 amended agreement. The first production payment to be paid in
1997 is estimated to be $1,035,000, of which $760,000 is accrued through
December 31, 1996. The production payment calculation is based upon the
difference between market gas prices compared to a table of rising prices and
based upon a table of declining volumes. The Partnership also agreed to exchange
with P&P its interests in fourteen non-operated Kansas wells for P&P's interests
in eighteen Kansas wells which the Partnership presently operates. Consequently,
the Partnership increased its working interest ownership from 80% to 100% in
each of these eighteen wells. In addition, the settlement confirmed the
Partnership's ownership of the gas gathering pipelines that deliver gas from the
Partnership's Oklahoma wells to its gas compressor facilities. The settlement
resulted in an earnings charge of approximately $4,263,000, a reduction of
liabilities of $200,000 and an increase in natural gas properties of $3,025,000
as reflected in the Partnership's 1996 financial statements. These amounts
represent the cash payment of $7,000,000 along with additional costs such as
royalty payments and legal fees. Along with the prospective production payment
previously mentioned, these adjustments represent all known significant
provisions for the settlement. ALL OF THE OUTSTANDING LITIGATION WITH P&P, AS
WELL AS ANY RELATED JUDGMENTS, THAT ARE DESCRIBED IN THE PARTNERSHIP'S 1995 FORM
10-K AND PREVIOUS 1996 FORMS 10-Q HAS BEEN DISMISSED. In addition, each party is
responsible for its own legal costs.
The 1996 operating expenses also reflect a charge of $395,000 (including
related interest through December 31, 1996) for Kansas tax reimbursements
received by the Partnership during the years 1983 to 1987. This charge results
from a ruling by the United States Court of Appeals for the District of Columbia
which overruled a previous order by the Federal Energy Regulatory Commission.
The Partnership, as well as numerous other parties, may pursue further judicial
review or regulatory relief with respect to this matter.
4. UNAUDITED NATURAL GAS RESERVE INFORMATION
Proved natural gas reserves are estimated quantities which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed natural gas reserves are reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods. The Partnership retained Calhoun Engineering, Inc., an
independent petroleum engineering consulting firm, to provide annual estimates
as of December 31 of each year of the Partnership's future net recoverable
natural gas reserves. Proved developed natural gas reserves for the year
beginning January 1, 1995 were revised to be more comparable to reserves of
others in the same field. This effect is shown in the tabulation below as 1995
revisions. The Partnership has no known reserves of crude oil. There have been
no events that have occurred since December 31, 1996 that would have a material
effect on the proved developed natural gas reserves. The estimated net
quantities of proved natural gas
27
<PAGE> 30
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
reserves (all of which were from developed properties located within the United
States) at December 31, 1996, 1995 and 1994 and the changes for the years then
ended were as follows:
<TABLE>
<CAPTION>
NATURAL GAS (MMCF)
--------------------------
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Estimated quantity, beginning of year................... 90,925 83,989 96,246
Revisions in previous estimates......................... (3,950) 15,701 (5,226)
Production.............................................. (8,725) (8,765) (7,031)
------ ------ ------
Estimated quantity, end of year......................... 78,250 90,925 83,989
====== ====== ======
Development costs incurred (in thousands of dollars).... $4,274 $1,149 $5,857
====== ====== ======
</TABLE>
The standardized measure of discounted future net cash flows related to
proved natural gas reserves at December 31, 1996, 1995 and 1994 (in thousands of
dollars) follows:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Future estimated gross revenues..................... $269,314 $173,699 $127,658
Future estimated gross production payment (ORRI).... 16,022 -- --
Future estimated production and development costs... 61,734 57,064 40,972
-------- -------- --------
Future estimated net revenues....................... 191,558 116,635 86,686
Future estimated net revenues 10% annual discount
for estimated timing of cash flows................ (76,712) (47,051) (33,565)
-------- -------- --------
Standardized measure of discounted future estimated
net revenues...................................... $114,846 $ 69,584 $ 53,121
======== ======== ========
Sales of natural gas produced, net of production
costs............................................. $(13,417) $ (9,851) $ (9,057)
Net changes in prices and production costs.......... 53,718 12,914 (11,516)
Revisions of previous quantity estimates............ (1,224) 8,367 (3,349)
Accretion of discount............................... 6,312 4,881 6,551
Other............................................... (127) 152 (523)
-------- -------- --------
Net change in standardized measure of discounted
future estimated net revenues..................... $ 45,262 $ 16,463 $(17,894)
======== ======== ========
</TABLE>
5. UNAUDITED QUARTERLY FINANCIAL DATA
Quarterly financial data for the last two years (dollars in thousands) is
summarized as follows:
<TABLE>
<CAPTION>
1996 QUARTER ENDED 1995 QUARTER ENDED
------------------------------------- -------------------------------------
SEPTEM- DECEM- SEPTEM- DECEM-
MARCH 31 JUNE 30 BER 30 BER 31 MARCH 31 JUNE 30 BER 30 BER 31
-------- ------- ------- ------ -------- ------- ------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Net operating revenues............... $4,697 $4,671 $2,388 $5,299 $3,311 $2,974 $2,909 $3,833
Net earnings (loss).................. 3,246 3,282 (2,310) 3,612 1,890 1,613 1,608 2,481
Net earnings (loss) per Unit......... 30c 30c (21c) 33c 17c 15c 15c 23c
</TABLE>
28
<PAGE> 31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
February 19, 1997 DORCHESTER HUGOTON, LTD.
P.A. PEAK, INC., GENERAL PARTNER
By /s/ PRESTON A. PEAK
-----------------------------------
Preston A. Peak, President
(Principal Executive and Financial
Officer)
JAMES E. RALEY, INC., GENERAL
PARTNER
By /s/ JAMES E. RALEY
-----------------------------------
James E. Raley, President
(Principal Executive and Financial
Officer)
By /s/ KATHLEEN A. RAWLINGS
-----------------------------------
Kathleen A. Rawlings, Controller
(Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<S> <S> <C>
P.A. PEAK, INC.
By /s/ PRESTON A. PEAK General Partner February 19, 1997
--------------------------------------------------
Preston A. Peak
President and Sole Director
JAMES E. RALEY, INC.
By /s/ JAMES E. RALEY General Partner February 19, 1997
--------------------------------------------------
James E. Raley
President and Sole Director
</TABLE>
29
<PAGE> 32
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER DESCRIPTION PAGE
------- ----------- ------------
<C> <S> <C>
3. -- Amended and Restated Certificate and Agreement of Limited
Partnership, as amended*
4.1 -- Depositary Agreement, as amended*
4.2 -- Specimen Depositary Receipt**
4.3 -- Nominee Agreement among the Partnership, Dorchester and
Nominee**
27. -- Financial Data Schedule
</TABLE>
- ---------------
* Previously filed and incorporated by reference to the respective Exhibits
(bearing the same exhibit numbers) to the Partnership's Form 10-Q for the
quarter ended June 30, 1995.
** Previously filed and incorporated by reference to the respective Exhibits
(bearing the same exhibit numbers) to the Partnership's Form 10-K for the
year ended December 31, 1995.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 115
<SECURITIES> 2,646
<RECEIVABLES> 3,054
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 5,918
<PP&E> 26,442
<DEPRECIATION> 9,677
<TOTAL-ASSETS> 22,683
<CURRENT-LIABILITIES> 4,150
<BONDS> 3,144
0
0
<COMMON> 0
<OTHER-SE> 15,389
<TOTAL-LIABILITY-AND-EQUITY> 22,683
<SALES> 17,055
<TOTAL-REVENUES> 17,055
<CGS> 9,225
<TOTAL-COSTS> 9,225
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 210
<INCOME-PRETAX> 7,830
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 7,830
<EPS-PRIMARY> .72
<EPS-DILUTED> .72
</TABLE>
