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1999 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, 1999 COMMISSION FILE NUMBER 0-10697
[DORCHESTER LOGO] DORCHESTER HUGOTON, LTD.
(Exact name of registrant as specified in its charter)
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TEXAS
(State or other jurisdiction of 75-1829064
incorporation or organization) (I.R.S. Employer Identification No.)
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1919 S. SHILOH ROAD, SUITE 600-LB48, GARLAND, TEXAS 75042-8234
(Address of principal executive offices, including Zip Code)
Registrant's telephone number, including area code: (972) 864-8610
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, 2000 was $86,923,000.
As of FEBRUARY 1, 2000, 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 1919 S. Shiloh Road, Suite 600-LB 48, Garland, Texas 75042-8234
(telephone (972) 864-8610) with field offices in Hooker, Oklahoma and Amarillo,
Texas and employed fourteen full time permanent employees (not including General
Partners) as of January 1, 2000. 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"). Depositary receipts for
units of limited partnership interest were originally distributed on August 20,
1982 in the form of a taxable property dividend.
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 Kansas infill wells and Oklahoma replacement
and Fort Riley wells) were drilled and have been producing since prior to 1954.
OKLAHOMA PROPERTIES
During 1998 the Partnership sold its working interest in one non-operated
Oklahoma well and, at the same time, acquired overriding royalty interests in
one Partnership owned and operated well. As a result, the Partnership's Oklahoma
working interests changed from including 128 natural gas wells (115.7 net wells)
to 127 natural gas wells (115.2 net wells) in the Guymon-Hugoton field.
Additionally, the Partnership's gross developed Oklahoma acreage changed from
80,501 acres (74,621 net acres) to 79,861 acres (74,301 net acres). The
Partnership continues to operate and own 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 a 10 well group (previously 11)
operated by an unaffiliated third party. The Partnership also has minor royalty
interests in various producing natural gas wells. During December 1999 the
Partnership acquired in Oklahoma a 1.6% royalty interest in one well operated by
the Partnership and in one non-Hugoton well operated by others.
Of the Partnership's 127 gas wells, 124 deliver natural gas through a 132
mile Partnership owned and operated gas pipeline gathering system to the
Partnership's Oklahoma gas compressor station. Beginning November 1, 1994, the
Partnership began operation of a new 5400 horsepower gas compression and
dehydration facility and delivered gas 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. During 1999 the Partnership
installed two field rental gas compression units in Oklahoma. See "Regulation
and Prices" for more information.
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 following Federal Energy
Regulatory Commission approval. Williams Field Services Company subsequently
processes the gas at its 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. The gas returned to the Partnership for subsequent
sale is of improved quality, including having the contaminant nitrogen removed.
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, which is sometimes referred to as Towanda.
At the time of drilling the Partnership's wells (primarily during the late
1940's), the Fort Riley zone was considered to contain
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salt water rather than natural gas and was frequently not penetrated. Based on
current information, the Fort Riley zone for the most part appears to be full of
water.
The Partnership believes that it is possible that some of the Partnership
acreage contains gas productive Fort Riley zones without excessive water
saturation. The Partnership's existing wells are mechanically not capable of
being deepened. Consequently, to explore in the Fort Riley zone requires
drilling a well and isolating the zone for testing. Considering the numerous
unknown factors such as possible salt water and possible previous lateral gas
migration in the Fort Riley, the Partnership continues to urge caution in
predicting the outcome of such exploration.
Thus far the Partnership has drilled and completed three wells to test the
Fort Riley zone. Each of the three wells replaced an existing gas well which was
plugged and abandoned as required by Oklahoma regulations. The first of the
three wells initially appeared to be favorable in both the Fort Riley zones and
Winfield/Krider zones; however, subsequent testing indicated that gas leaked
upward through the shale rock layer separating the zones, causing Fort Riley
evaluations to be inconclusive. The first of the three wells recently produced
393 MCFD at 68 psig which is an improvement over the plugged well's previous 105
MCFD at 24 psig. The second of the three Fort Riley test wells was not as
successful, producing 78 MCFD while pumping 30 bbls of water per day. This
second well replaced a Winfield/Krider well that produced 175 MCFD with no
water. In December 1998, this second Fort Riley well was plugged and recompleted
in the Winfield/Krider zone and recently produced 171 MCFD at 19 psig. The third
Fort Riley test recently produced between 40 to 110 MCFD at 18 psig. The third
well's production is not stable as a result of water encroachment which has
required more frequent bailing. The third Fort Riley test replaced a
Winfield/Krider well that produced 85 MCFD at 20 psig.
KANSAS PROPERTIES
The Partnership currently operates and owns 100% of the working interest in
20 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 26 mile gas gathering pipeline and compression facility
owned by the Partnership and is sold in the field at spot market prices.
Compared to 1997 and 1998, Kansas 1999 sales volumes have decreased. Such
decreases are primarily a result of declining Kansas reservoir pressures
experienced by the Partnership and other producers in the area. On November 5,
1997 the Partnership began operation of additional gas gathering pipelines and
seven rental gas compressor units which are scattered over a ten mile area.
Initial results showed a favorable increase in gas sales accompanied by an
increase in condensed water accumulation in the gathering pipelines. The total
capital cost was approximately $470,000. The Partnership's Kansas operating
costs for such field gas compression operations were approximately $344,000 in
1998 and $288,000 in 1999.
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 producing wells through 1990 and one each in 1995, 1996 and
1997. One infill well was plugged in 1992 and another in 1993 for economic
reasons.
During July 1998 the Partnership acquired in Kansas a royalty interest of
approximately 3% that included two wells operated by the Partnership and two
non-Hugoton wells operated by others. 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.
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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 transportation of natural gas after sale by the Partnership is 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. Allowable gas production
rates have been, and are, to varying degrees, 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. 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 Oklahoma 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 127 wells, there are about 1,350
currently producing gas wells in the Guymon-Hugoton Field owned by both
independent producers and major oil and gas companies. Previously, a few
producers and numerous other interested parties in the area were 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 have actively opposed 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 ("OCC")
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 in the Guymon-Hugoton field rules allowing infill drilling 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. THE OUTCOME AND COST OF INFILL DRILLING IS UNPREDICTABLE. In late
February 1997, Oklahoma did not pass legislation that would have allowed "infill
drilling". Similar proposed legislation may arise in the future. On June 21,
1999 Oklahoma enacted legislation that clarifies who must receive notices of any
application for Guymon-Hugoton infill drilling. Currently no such applications
have been filed and such filings are expected to be controversial and require
lengthy regulatory proceedings.
On October 28, 1997 the OCC, which administers oil and gas conservation in
Oklahoma, conducted a hearing on a proposal to change the allowable amount of
production per well in the Guymon-Hugoton field. The hearing included
contradictory viewpoints that the proposal encouraged infill drilling vs. that
the proposal had no effect on the infill drilling issue. On February 4, 1998 the
OCC adopted rules that essentially removed production volume limits from nearly
all wells in the Guymon-Hugoton field effective July 1, 1998 and specifically
provided that the rule changes have no bearing on
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the question of infill drilling which must be decided separately. Thus far only
one company on adjoining acreage has installed gas compression to try to benefit
from Oklahoma's removal of production limits. The Partnership elected to install
similar rental compression to stay competitive. At present, five of the
Partnership's wells are assisted by such field compression. Three of the wells
have increased production from an average of 214 MCFD to 378 MCFD. The other two
wells have increased from an average of 51 MCFD to 76 MCFD, which includes the
results of water removal. Operating costs are expected to increase by $75,000 to
$85,000 per year as a result of operating two compressor units for the five
wells. The increase in production has more than offset costs of compression.
Further activities by others resulting from the field rule changes and related
costs and/or benefits to the Partnership are unpredictable.
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. During 1999 the lowest price was $1.59/MMBTU
in March and the highest was $3.04/MMBTU in November. The Partnership
anticipates continued fluctuations in marketplace pricing. See Note 1 to the
Financial Statements for a discussion regarding material customers and
contracts.
The FERC allows 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 effect on the
Partnership in Kansas has been minimal since only one of the two transmission
pipelines to which the Partnership delivered gas became a non-regulated
gathering pipeline in 1996. Since then the Partnership's gas from the 20 Kansas
wells was delivered directly to a transmission pipeline or sold to Duke Energy
Field Services, Inc. at the outlet of the Partnership's compressors. On May 1,
1996 the Partnership also negotiated a four-year gas sales agreement with WFS
Gas Resources Company (part of Williams Companies, Inc.) providing for
gathering, compression, and sale of gas at market prices. This agreement covers
only 3 wells (in which the Partnership has 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. Both Kansas and
Oklahoma have adopted state regulation of gas gathering pipeline systems
available for hire which excludes the Partnership's facilities. Additionally,
current court decisions in both Kansas and Oklahoma sharply restrict the
practice of requiring royalty owners to bear their share of gas gathering and
compression costs. The Partnership has never charged royalty owners for such
costs.
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 and other resources greater than the
Partnership. 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") on July 24, 1997 issued the
Partnership an air emissions operating permit for its Kansas compression
facility. Previously such a permit was not required. At present, no permits are
necessary for the seven rental field compressors installed in Kansas during 1997
or the two rental field compressors installed in Oklahoma during 1999. 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.
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DEPOSITARY RECEIPTS AND THE DEPOSITARY AGREEMENT
Immediately subsequent to its formation, all of the Partnership's units of
limited partnership interest ("Units") were deposited with an authorized
depositary ("Depositary"), to be held in accordance with the Depositary
Agreement. Effective September 8, 1998 the Depositary became BankBoston, N.A.,
c/o Boston EquiServe, L.P., P.O. Box 8040, Boston, MA 02266. 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.
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 would have been
made on the open market, in private transactions, or otherwise. Purchases from
the General Partners were excluded from the repurchase program. All Units
repurchased under the program would be retired resulting in a decrease in both
Units issued and Units outstanding. No Units would have been held as "Treasury
Units". There was no assurance or obligation that the repurchase program would
result in any purchase of Units. The Partnership believed the repurchase program
was 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. On October
26, 1999 the Partnership terminated the authorization to repurchase and retire
Units. No Units were repurchased pursuant to such authorization.
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 1999 and 1998 were as follows:
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1999 1998
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LOW HIGH VOLUME LOW HIGH VOLUME
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First Quarter..................... 9 3/8 10 1/2 867,000 13 1/2 16 1/4 768,000
Second Quarter.................... 9 11 1/2 388,000 14 1/2 16 3/4 544,000
Third Quarter..................... 10 1/8 13 1/4 481,000 10 1/8 14 7/8 498,000
Fourth Quarter.................... 9 13 1/4 476,000 10 13 482,000
</TABLE>
As of January 1, 2000, there were approximately 4,100 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
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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.
Effective with the third quarter 1995 distribution, the Partnership's
transfer agents have paid all distributions as declared. Distributions per Unit
have been as follows:
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YEAR ENDED DECEMBER 31,
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QUARTER 1982 1983 1984 1985/86 1987 1988 1989/90/91 1992 1993 1994/95/96 1997/98/99
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First................ N/A $.02 $.01 $.01 $.02 $.03 $.05 $.05 $.12 $.17 $.18
Second............... N/A .01 .01 .01 .02 .04 .05 .05 .15 .17 .18
Third................ $.01 .01 .01 .01 .03 .04 .05 .05 .17 .17 .18
Fourth............... .02 .01 .01 .02 .03 .04 .05 .08 .17 .17 .18
--- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Total................ $.03 $.05 $.04 $.05 $.10 $.15 $.20 $.23 $.61 $.68 $.72
=== ==== ==== ==== ==== ==== ==== ==== ==== ==== ====
</TABLE>
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 ($484 for 1999 and $507 for 1998) 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
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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 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.
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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, 2000 and other persons,
excluding depositaries, of record on January 1, 2000 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..... 14,706 .14%
</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, 1999.
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 it 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.
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 77, Investor, and James E. Raley, Inc., whose sole
shareholder is James E. Raley, age 60, Engineer. Kathleen A. Rawlings, age 42,
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.
Mr. Fulgham presently serves as Chairman and Chief Executive Officer of Global
Industrial Technologies, Inc. and is a director of NCH Corporation and Global
Industrial Technologies, Inc. Mr. Blank is currently a consultant active in the
natural gas industry. Previously, he was the Executive Vice President of
8
<PAGE> 11
Rockland Pipeline Company in Houston, Texas. He also serves on the Board of
Directors of Panther Natural Gas Company.
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, 1998 and August
9, 1995 provides for a management fee to be divided among the General Partners
in an annual aggregate amount of $350,000 (previously $250,000 effective January
1, 1995) 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>
1997................................... $107,797 $326,022(a) $433,819
1998................................... $ 88,830 $407,055(a) $495,885
1999................................... $ 88,509 $407,484(a) $495,993
</TABLE>
- ---------------
(a) Includes the amount of taxable medical insurance premiums and payments of
$5,225, $5,225, and $5,975 for James E. Raley in 1997, 1998, and 1999,
respectively.
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. During 1999, the General
Partners were reimbursed a total of $33,752 for all expenses incurred by them on
behalf of the Partnership, including their general and administrative expenses.
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
9
<PAGE> 12
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 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
10
<PAGE> 13
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.
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 (since 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 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. There were no
meetings of the Unitholders held during 1999. 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,
11
<PAGE> 14
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.
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 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.
12
<PAGE> 15
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 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.
13
<PAGE> 16
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 WAS NOT AFFECTED BY EXISTING TAX
PROVISIONS THAT CAUSED 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. 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. No period of limitation extensions have
been granted at this time.
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 Unitholders 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 1999.
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, 1999, 1998, 1997, 1996, AND 1995
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Net operating revenues....................... $15,302 $15,366 $19,159 $17,055 $13,027
Net earnings................................. $ 9,046 $ 9,010 $12,665 $ 7,830 $ 7,592
Net earnings per Unit........................ $ 0.83 $ 0.83 $ 1.17 $ 0.72 $ 0.70
Cash distributions per Unit.................. $ 0.72 $ 0.72 $ 0.72 $ 0.68 $ 0.68
Total assets at December 31.................. $28,165 $26,444 $25,215 $22,683 $19,601
Notes payable -- long term................... $ 100 $ 100 $ 122 $ 3,144 $ 1,725
Partnership capital at December 31........... $24,338 $22,641 $20,841 $15,389 $14,499
</TABLE>
14
<PAGE> 17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. As shown in the following table, overall gas sales
volumes were down 3% from 1997 to 1998 and down 7% from 1998 to 1999. Natural
gas market prices were down 18% from 1997 to 1998 and up 7% from 1998 to 1999.
The Partnership's 1999 fourth quarter weighted average gas sales prices were up
26% compared to 1998 ($2.62 v. $2.08 per MCF). Net earnings were $12,665,000 in
1997, $9,010,000 in 1998 and $9,046,000 in 1999. Operating cash flows were
$15,482,000 in 1997, $10,501,000 in 1998 and $11,045,000 in 1999. On May 15,
2000 the Partnership will pay an Oklahoma production payment of $730,000 for the
year ended February 29, 2000, of which approximately $600,000 was accrued
through December 31, 1999.
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. Year end cash and cash equivalents totaled
$4,167,000 for 1998 and $7,017,000 for 1999. The Partnership's ownership of
Exxon (now Exxon Mobil Corporation) common stock increased from 54,000 to 64,000
shares during 1998.
The Partnership's 5,400 horsepower gas compression and dehydration facility
in Oklahoma has continued to operate satisfactorily since its start-up in
November 1994. Major maintenance was performed in 1998. The Partnership
anticipates normal gradual increases in repairs. Electronic measurement was
installed on the Oklahoma gas gathering pipelines during 1996. Field consumption
of natural gas at the compression and dehydration facilities is estimated to be
approximately 4.5% of the Oklahoma inlet gas volume and 10% in Kansas as a
result of field compression. The Partnership anticipates gradual increases in
Oklahoma field operating costs and expenses as repairs to its 50-year-old
pipelines and gas wells become more frequent and as pressures eventually
decline. The Partnership does not anticipate significant replacement of these
items at this time. During 1999, the Partnership concluded testing and
reinstallation of anodes (corrosion protection devices) on the Oklahoma gas
pipeline gathering system.
The routine workover of wells in Oklahoma includes fracture treating (the
creation of cracks in the formation to assist gas flow toward the well bore from
the producing zones). Currently, the Partnership has fracture treated 17 wells
in Oklahoma which includes 10 wells during 1999. Of the 17 wells, 14 increased
in gas production volume and 15 increased in gas pressure. THE COMBINATION OF AN
INCREASE IN PRESSURE AND VOLUME RESULTED IN AN OVERALL INCREASE OF 49% IN GAS
RESERVES FOR THE 17 WELLS. Such fracture treatments to date have cost from
$20,000 to $35,000 per well. THE RESULTS OF SUCH FRACTURE TREATING CAN VARY
WIDELY FROM WELL TO WELL AND MAY NOT BE SUCCESSFUL. HOWEVER, AT PRESENT, TYPICAL
OKLAHOMA PER WELL VOLUME INCREASES HAVE BEEN SIGNIFICANT, CURRENTLY AVERAGING
107% (133 TO 275 MCF PER DAY). The Partnership anticipates continuing additional
fracture treating during 2000.
15
<PAGE> 18
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
------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Sales Volumes:
Oklahoma................................................. 5,580 5,739 5,746
Kansas................................................... 1,320 1,696 1,936
------ ------ ------
Total............................................ 6,900 7,435 7,682
====== ====== ======
Weighted Average Sales Prices:
Oklahoma................................................. $ 2.28 $ 2.11 $ 2.60
Kansas................................................... 2.36 2.22 2.63
Overall weighted average................................. 2.30 2.14 2.61
</TABLE>
Oklahoma 1999 gas sales volumes were within 3% of the 1998 and 1997 volumes
partly because of volume increases from fracture treating offsetting natural
declines. The Partnership drilled and completed one Fort Riley test well in 1997
and two in 1998. The second well has been plugged and recompleted in an upper
zone -- see the Business and Properties of the Partnership -- Oklahoma
Properties section of this annual report. The Partnership will continue to
evaluate the results of the third Fort Riley well (especially in view of shut-in
pressures exceeding 300 psig) to seek a method of increasing gas flow without
increasing water production. Meanwhile, the Partnership anticipates installing a
pumping unit to remove water from the well bore and hopefully improve production
volume. Further Fort Riley drilling will await the results of this evaluation.
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 infill drilling and monitoring
activities in the field resulting from removal of production quantity
restrictions in the Guymon-Hugoton field.
During 1997 the Partnership drilled and completed one additional infill
well in Kansas. Also during 1997, the Partnership began operation of seven
Kansas skid-mounted field rental gas compressor units -- see the Business and
Properties of the Partnership section of this Annual Report. Kansas 1999 sales
volumes were lower than 1998 and 1997 as a result of declining volumes and
pressures typical of other producers in that area. The use of field compression,
which increased volume initially, helped lessen the decline on an annual basis.
The Partnership, together with other producers, are currently seeking Kansas
regulatory permission to employ field compressors to operate the wells at a
vacuum. The proposal is opposed by some producers and neither the outcome nor
the possible effect upon allowable production volume is predictable.
The Partnership is continuing to monitor the activity on nearby acreage in
the Council Grove formation. At present 15 wells have been drilled by others.
The Partnership's ownership includes the Council Grove formation underlying most
of its Oklahoma acreage. IT IS NOT KNOWN IF SUCH MONITORING WILL RESULT IN ANY
PLANS BY THE PARTNERSHIP TO ATTEMPT A COUNCIL GROVE WELL; PREVIOUS PRELIMINARY
REVIEWS YIELDED UNFAVORABLE FORECASTS. However, recent results by others have
varied from 37 MCF per day with water production to over 1,000 MCF per day.
Production volumes in subsequent months have varied with most wells showing
decreases. Blue Star Resources Inc.'s current total production from the three
Council Grove wells on the Partnership's acreage is approximately 38 MCFD, 18
MCFD and 6 MCFD. The Partnership has a minor overriding royalty interest in the
three wells.
As previously reported, the accounting firm that has, for years, processed
the Partnership's 4,000 to 5,000 individualized K-1's previously notified us
that their current computer software, while fully able to process 1999 tax
returns in early year 2000, would not be able to process Year 2000 tax returns
in early 2001. Subsequently, the Partnership was notified during the third
quarter of 1999 that the accounting firm had begun developing new software and
had acquired another firm that had a Year 2000 compliant product. However,
conversion of data to the new software will still be necessary.
16
<PAGE> 19
Consequently, the Partnership believes it could incur estimated total
expenditures of $150,000 to $200,000 during calendar year 2000 and 2001 on K-1
preparation and/or conversion costs in addition to current K-1 processing costs.
Except as stated above, thus far, the Partnership has been essentially
unaffected by the change from calendar year 1999 to 2000.
As previously discussed in the 1997 and 1998 Annual Reports, the
Partnership is reviewing its strategic alternatives in light of the various
mergers and other business transactions occurring in the natural gas and energy
industry. Although no decision to sell or combine the Partnership's business
with others has been made, the Partnership anticipates possible discussions with
third parties which could result in such a decision. The Partnership has no
timetable for any such discussions, and there is no assurance that any such
discussions will lead to a transaction. During the first quarter of 1998 the
Partnership adopted a severance policy which would provide up to approximately
$2.8 million of severance payments. Please see Note 3 to the Financial
Statements.
17
<PAGE> 20
FINANCIAL INFORMATION
Financial Statements:
Statements of Earnings for the Years Ended December 31, 1999, 1998 and
1997.
Statements of Comprehensive Income for the Years Ended December 31, 1999,
1998 and 1997.
Balance Sheets as of December 31, 1999 and 1998.
Statements of Changes in Partnership Capital for the Years Ended December
31, 1997, 1998 and 1999.
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and
1997.
Notes to Financial Statements.
Exhibits:
<TABLE>
<CAPTION>
PREVIOUSLY FILED AND INCORPORATED WITH
NUMBER DESCRIPTION (BEARING THE SAME EXHIBIT NUMBER)
------ ----------- --------------------------------------
<C> <S> <C>
3 -- Amended and Restated Certificate and Agreement of
Limited Partnership, as amended June 30, 1995 Form 10-Q
3.01 -- Certificates of Amendments to the Agreement of Limited
Partnership dated July 2, 1997 and December 15, 1997 December 31, 1997 Form 10-K
3.02 -- Certificate of Amendment to the Agreement of Limited
Partnership dated April 3, 1998 March 31, 1998 Form 10-Q
4.1 -- Depositary Agreement, as amended June 30, 1995 Form 10-Q
4.2 -- Specimen Depositary Receipt December 31, 1995 Form 10-K
4.3 -- Nominee Agreement among the Partnership, Dorchester and
Nominee December 31, 1995 Form 10-K
27 -- Financial Data Schedule Filed herewith
</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.
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. 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, 1999 and 1998, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1999 in conformity
with generally accepted accounting principles.
GRANT THORNTON LLP
Dallas, Texas
February 11, 2000
18
<PAGE> 21
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
STATEMENTS OF EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Net operating revenues:
Natural gas sales......................................... $15,849 $15,901 $20,049
Other..................................................... 198 199 183
Production payment (ORRI)................................. (745) (734) (1,073)
------- ------- -------
Total net operating revenues...................... 15,302 15,366 19,159
------- ------- -------
Costs and expenses:
Operating................................................. 2,678 2,619 2,457
Production taxes.......................................... 910 921 1,193
Depreciation, depletion and amortization.................. 1,903 2,015 1,916
General and administrative:
Tax and regulatory reporting........................... 176 143 174
Depositary and transfer agent fees..................... 24 18 10
Other.................................................. 363 371 376
Management fees........................................... 490 491 428
Interest expense.......................................... 37 40 106
Other income.............................................. (325) (262) (166)
------- ------- -------
Total costs and expenses.......................... 6,256 6,356 6,494
------- ------- -------
Net earnings................................................ $ 9,046 $ 9,010 $12,665
======= ======= =======
Net earnings per Unit....................................... $ 0.83 $ 0.83 $ 1.17
======= ======= =======
</TABLE>
STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Net earnings................................................ $ 9,046 $ 9,010 $12,665
Unrealized holding gain on available for sale securities.... 476 635 658
------- ------- -------
Comprehensive income........................................ $ 9,522 $ 9,645 $13,323
======= ======= =======
</TABLE>
See Notes to Financial Statements
19
<PAGE> 22
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Current assets:
Cash and temporary cash investments....................... $ 7,017 $ 4,167
Restricted cash (Note 3).................................. 390 379
Investments -- available for sale......................... 5,156 4,680
Accounts receivable....................................... 1,555 1,645
Prepaid expenses and other current assets................. 141 152
------- -------
Total current assets................................... 14,259 11,023
------- -------
Property and equipment -- at cost:
Natural gas properties (full cost method)................. 28,143 27,790
Other..................................................... 1,060 1,046
------- -------
Total................................................ 29,203 28,836
Less accumulated depreciation, depletion and amortization:
Full cost depletion....................................... 14,863 13,076
Other..................................................... 434 339
------- -------
Total................................................ 15,297 13,415
------- -------
Net property and equipment................................ 13,906 15,421
------- -------
Total assets......................................... $28,165 $26,444
======= =======
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
Accounts payable.......................................... $ 252 $ 260
Production and property taxes payable..................... 630 647
Royalties payable......................................... 889 839
Distributions payable to unitholders...................... 1,956 1,957
------- -------
Total current liabilities.............................. 3,727 3,703
Notes payable -- long-term.................................. 100 100
------- -------
Total liabilities...................................... 3,827 3,803
------- -------
Commitments and contingencies (Note 3)
Partnership capital:
General partners.......................................... 140 128
Unitholders............................................... 21,559 20,350
Accumulated other comprehensive income.................... 2,639 2,163
------- -------
Total partnership capital.............................. 24,338 22,641
------- -------
Total liabilities and partnership capital............ $28,165 $26,444
======= =======
</TABLE>
See Notes to Financial Statements
20
<PAGE> 23
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
ACCUMULATED
OTHER
GENERAL COMPREHENSIVE
YEAR PARTNERS UNITHOLDERS INCOME TOTAL
- ---- -------- ----------- ------------- -------
<S> <C> <C> <C> <C>
1997
Balance at December 31, 1996.................. $ 68 $14,451 $ 870 $15,389
Net earnings.................................. 127 12,538 -- 12,665
Net unrealized holding gain on investments
available for sale......................... -- -- 658 658
Distributions ($0.72 per Unit)................ (78) (7,736) -- (7,814)
Other......................................... (1) (56) -- (57)
---- ------- ------ -------
Balance at December 31, 1997.................. 116 19,197 1,528 20,841
---- ------- ------ -------
1998
Net earnings.................................. 90 8,920 -- 9,010
Net unrealized holding gain on investments
available for sale......................... -- -- 635 635
Distributions ($0.72 per Unit)................ (78) (7,736) -- (7,814)
Other......................................... -- (31) -- (31)
---- ------- ------ -------
Balance at December 31, 1998.................. 128 20,350 2,163 22,641
---- ------- ------ -------
1999
Net earnings.................................. 90 8,956 -- 9,046
Net unrealized holding gain on investments
available for sale......................... -- -- 476 476
Distributions ($0.72 per Unit)................ (78) (7,736) -- (7,814)
Other......................................... -- (11) -- (11)
---- ------- ------ -------
Balance at December 31, 1999.................. $140 $21,559 $2,639 $24,338
==== ======= ====== =======
</TABLE>
See Notes to Financial Statements
21
<PAGE> 24
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings.............................................. $ 9,046 $ 9,010 $12,665
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Depreciation, depletion and amortization............... 1,903 2,015 1,916
(Gain) loss on sale of property and equipment.......... (8) (13) 1
Other.................................................. (11) (31) (57)
Changes in current assets and liabilities:
Restricted cash...................................... (11) (379) --
Accounts receivable.................................. 90 441 968
Prepaid expenses and other current assets............ 11 (16) (33)
Accounts payable, taxes and royalties payable........ 25 (526) 22
------- ------- -------
Net cash provided by operating activities................... 11,045 10,501 15,482
------- ------- -------
Cash flows from investing activities:
Capital expenditures...................................... (391) (1,136) (1,550)
Purchase of available for sale securities................. -- (741) --
Cash received on sale of property and equipment........... 12 58 53
------- ------- -------
Net cash used by investing activities....................... (379) (1,819) (1,497)
------- ------- -------
Cash flows from financing activities:
Proceeds from long-term borrowing......................... -- -- 7,200
Loan payments............................................. -- (44) (10,247)
Distributions paid to Unitholders......................... (7,816) (7,815) (7,709)
------- ------- -------
Net cash used by financing activities....................... (7,816) (7,859) (10,756)
------- ------- -------
Increase in cash and temporary cash investments............. 2,850 823 3,229
Cash and temporary cash investments at beginning of year.... 4,167 3,344 115
------- ------- -------
Cash and temporary cash investments at end of year.......... $ 7,017 $ 4,167 $ 3,344
======= ======= =======
Supplemental cash flow and other information:
Interest paid (no interest was capitalized)............... $ 37 $ 43 $ 109
======= ======= =======
Distributions declared but not paid....................... $ 1,956 $ 1,957 $ 1,958
======= ======= =======
</TABLE>
See Notes to Financial Statements
22
<PAGE> 25
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations -- The Partnership's operations consist principally of
the operation of natural gas properties located in Kansas and Oklahoma.
Basis of Presentation -- Per-Unit information is calculated by dividing the
99% interest owned by Unitholders by the 10,744,380 Units outstanding.
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 shares of Exxon
Mobil Corporation (previously Exxon Corporation) common stock and are classified
as available for sale. At December 31, 1999 and 1998, the carrying value of this
stock, based on the quoted market price, was $5,156,000 and $4,680,000,
respectively, and the cost was $2,517,455 for both years.
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 estimated 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 estimates of 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.
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 $350,000 effective January 1, 1998 (previously
$250,000) 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.
23
<PAGE> 26
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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, 1999 the net balance owed the Partnership is approximately 14,000
MCF compared to 1,000 MCF at December 31, 1998.
Other Agreements -- Effective May 1, 1997, the Partnership's Kansas gas was
committed for sale and processing to PanEnergy Field Services, Inc. (now Duke
Energy Field Services, Inc.) for a period of 3 years and year to year
thereafter. Duke Energy will pay based on an index of the market price in the
field plus a premium. Similarly, effective July 1, 1999 the Partnership's
Oklahoma gas was committed for sale to Williams Energy Services Company
("WESCO") for a one-year period at a premium over the market price index. During
1996, the Partnership's Oklahoma gas began a five-year commitment to Williams
Field Services Company for delivery through a processing facility. The quantity
sold to WESCO 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, 1999 the imbalance was
approximately 22,000 MMBTU owed the Partnership compared to 14,000 MMBTU owed to
WESCO at December 31, 1998.
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, 1999, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
PURCHASER PURCHASER PURCHASER
YEAR "A" "B" "C"
---- --------- --------- ---------
<S> <C> <C> <C>
1999.................................... 80% 19%
1998.................................... 76% 23%
1997.................................... 70% 13% 16%
</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.
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
24
<PAGE> 27
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 $135,125,
$134,186, and $130,937, were made to eligible employees' accounts for 1999, 1998
and 1997, 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. The Partnership also rents nine
skid-mounted field gas compressor units on a month to month basis. The
Partnership also has various prepaid site leases in Kansas and Oklahoma. Total
rental expense was $333,000, $324,000, and $122,000 for the years ended December
31, 1999, 1998 and 1997, respectively.
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") which was last renewed on July 31, 1998. The current borrowing base is
$6,000,000, which will 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 8.5% on December 31, 1999. All amounts borrowed under this
facility become due and payable on July 31, 2001. As of December 31, 1999, a
letter of credit totaling $25,000 was issued under the credit facility and the
amount borrowed was $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 1999 and 1998 weighted average amounts borrowed under
the Credit Agreement was $100,000 and $100,000, respectively.
3. COMMITMENTS AND CONTINGENCIES
Since its first annual payment in 1997, each May the Partnership pays an
Oklahoma production payment (calculated through the prior February) that is
based upon the difference between market gas prices compared to a table of
rising prices and based upon a table of declining volumes.
Through 1998 the Partnership recorded $450,000 (which included related
interest) towards a request from Panhandle Eastern Pipe Line Company ("PEPL")
for refund of Kansas tax reimbursements received by the Partnership during the
years 1983 to 1987. These charges resulted 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. On March 9, 1998 $151,757 was paid
to PEPL. An additional $366,633, which is still awaiting possible
settlement/regulatory/judicial/legislative action, was placed into an escrow
account. On March 2, 1999, $2,840 was released from escrow to PEPL. At December
31, 1999, the value of the escrow is approximately $390,000. The escrowed funds
include
25
<PAGE> 28
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
amounts that could possibly be waived, recovered or recoverable from others, of
which $34,000 has been recorded as an allowance for bad debt on the
Partnership's books in the event it is not waived and deemed uncollectible.
The Partnership is involved in a few other legal and/or administrative
proceedings arising in the ordinary course of its gas business, none of which
have predictable outcomes and none of which are believed to have any significant
effect on financial position or operating results.
The Partnership adopted a severance policy during the first quarter of
1998. Benefits are generally payable to employees and General Partner(s) in the
event of a reduction in force or the elimination of a position or group of
positions. The policy provides for up to approximately $2.8 million of severance
payments if such obligations occur.
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, Blair & Associates, Inc.,
(or its predecessor, 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. The
Partnership has no known reserves of crude oil. There have been no events that
have occurred since December 31, 1999 that would have a material effect on the
estimated proved developed natural gas reserves.
In accordance with SFAS No. 69 and Securities and Exchange Commission
("SEC") rules and regulations, the following information is presented with
regard to the Partnership's gas reserves, all of which are proved, developed and
located in the United States.
The SEC has adopted SFAS No. 69 disclosure guidelines for oil and gas
producers. These rules require the Partnership to include as a supplement to the
basic financial statements a standardized measure of discounted future net cash
flows relating to proved oil and gas reserves.
The standardized measure, in management's opinion, should be examined with
caution. The basis for these disclosures is an independent petroleum engineer's
reserve study which contains imprecise estimates of quantities and rates of
production of reserves. Revision of prior year estimates can have a significant
impact on the results. Also, exploration and production improvement costs in one
year may significantly change previous estimates of proved reserves and their
valuation. Values of unproved properties and anticipated future price and cost
increases or decreases are not considered. Therefore, the standardized measure
is not necessarily a "best estimate" of the fair value of the Partnership's gas
properties or of future net cash flows.
26
<PAGE> 29
DORCHESTER HUGOTON, LTD.
(A TEXAS LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The following summaries of changes in reserves and standardized measure of
discounted future net cash flows were prepared from estimates of proved reserves
developed by independent petroleum engineers.
SUMMARY OF CHANGES IN PROVED DEVELOPED RESERVES
<TABLE>
<CAPTION>
NATURAL GAS (MMCF)
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Estimated quantity, beginning of year................... 64,147 71,431 78,250
Revisions in previous estimates......................... 1,478 581 1,320
Production.............................................. (7,416) (7,865) (8,139)
------- ------- -------
Estimated quantity, end of year......................... 58,209 64,147 71,431
======= ======= =======
Depletion of natural gas properties (per MCF)........... $ 0.24 $ 0.24 $ 0.22
======= ======= =======
Development costs incurred (in thousands of dollars).... $ 348 $ 963 $ 1,385
======= ======= =======
Leasehold acquisitions (in thousands of dollars)........ $ 16 $ 387 --
======= ======= =======
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Future estimated gross revenues...................... $118,516 $113,517 $152,982
Future estimated gross production payment (ORRI)..... (5,353) (3,833) (6,421)
Future estimated production and development costs.... (45,930) (46,245) (62,495)
-------- -------- --------
Future estimated net revenues........................ 67,233 63,439 84,066
Future estimated net revenues 10% annual discount for
estimated timing of cash flows..................... (22,851) (22,830) (28,936)
-------- -------- --------
Standardized measure of discounted future estimated
net revenues....................................... $ 44,382 $ 40,609 $ 55,130
======== ======== ========
Sales of natural gas produced, net of production
costs.............................................. $(11,525) $(11,633) $(15,346)
Net changes in prices and production costs........... 8,717 (8,821) (57,714)
Revisions of previous quantity estimates............. 2,509 488 2,363
Accretion of discount................................ 3,627 4,917 10,272
Other................................................ 445 528 709
-------- -------- --------
Net change in standardized measure of discounted
future estimated net revenues...................... $ 3,773 $(14,521) $(59,716)
======== ======== ========
</TABLE>
5. UNAUDITED QUARTERLY FINANCIAL DATA
Quarterly financial data for the last two years (dollars in thousands
except per unit data) is summarized as follows:
<TABLE>
<CAPTION>
1999 QUARTER ENDED 1998 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...... $3,064 $3,508 $4,337 $4,393 $4,097 $3,991 $3,565 $3,713
Net earnings................ 1,602 1,889 2,769 2,786 2,464 2,361 1,950 2,235
Net earnings per Unit....... $ 0.15 $ 0.17 $ 0.26 $0.25 $ 0.23 $ 0.22 $ 0.18 $ 0.20
</TABLE>
27
<PAGE> 30
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 17, 2000 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>
<C> <S> <C>
P.A. PEAK, INC.
By /s/ PRESTON A. PEAK General Partner February 17, 2000
-------------------------------------------------
Preston A. Peak
President and Sole Director
JAMES E. RALEY, INC.
By /s/ JAMES E. RALEY General Partner February 17, 2000
-------------------------------------------------
James E. Raley
President and Sole Director
</TABLE>
28
<PAGE> 31
EXHIBIT INDEX
<TABLE>
<CAPTION>
PREVIOUSLY FILED AND INCORPORATED WITH
NUMBER DESCRIPTION (BEARING THE SAME EXHIBIT NUMBER)
------ ----------- --------------------------------------
<C> <S> <C>
3 -- Amended and Restated Certificate and Agreement of
Limited Partnership, as amended June 30, 1995 Form 10-Q
3.01 -- Certificates of Amendments to the Agreement of Limited
Partnership dated July 2, 1997 and December 15, 1997 December 31, 1997 Form 10-K
3.02 -- Certificate of Amendment to the Agreement of Limited
Partnership dated April 3, 1998 March 31, 1998 Form 10-Q
4.1 -- Depositary Agreement, as amended June 30, 1995 Form 10-Q
4.2 -- Specimen Depositary Receipt December 31, 1995 Form 10-K
4.3 -- Nominee Agreement among the Partnership, Dorchester and
Nominee December 31, 1995 Form 10-K
27 -- Financial Data Schedule Filed herewith
</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.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 7,017
<SECURITIES> 5,156
<RECEIVABLES> 1,555
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 14,259
<PP&E> 29,203
<DEPRECIATION> 15,297
<TOTAL-ASSETS> 28,165
<CURRENT-LIABILITIES> 3,727
<BONDS> 100
0
0
<COMMON> 0
<OTHER-SE> 24,338
<TOTAL-LIABILITY-AND-EQUITY> 28,165
<SALES> 15,302
<TOTAL-REVENUES> 15,302
<CGS> 6,256
<TOTAL-COSTS> 6,256
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 37
<INCOME-PRETAX> 9,046
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,046
<EPS-BASIC> .83
<EPS-DILUTED> .83
</TABLE>
