FORM 10-K405
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Annual Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1998
Commission File Number 33-10346-07 (1979-1 Program)
33-10346-08 (1979-2 Program)
DYCO 1979 OIL AND GAS PROGRAMS
(TWO LIMITED PARTNERSHIPS)
(Exact name of registrant as specified in its charter)
41-1358013 (1979-1 Program)
Minnesota 41-1358015 (1979-2 Program)
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
Samson Plaza
Two West Second Street
Tulsa, Oklahoma 74103
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (918) 583-1791
Securities registered pursuant to Section 12(b) of the Act: None.
Securities registered pursuant to Section 12(g) of the Act:
Units of limited partnership interest
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 the
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-K405 or any amendment to
this Form 10-K405. [X]
The units of limited partnership are not publicly traded, therefore,
registrant cannot compute the aggregate market value of the voting units held by
non-affiliates of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE: None.
-1-
<PAGE>
FORM 10-K405
DYCO 1979 OIL AND GAS PROGRAMS
(Two Minnesota limited partnerships)
TABLE OF CONTENTS
PART I.......................................................................3
ITEM 1. BUSINESS...................................................3
ITEM 2. PROPERTIES.................................................7
ITEM 3. LEGAL PROCEEDINGS.........................................12
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF LIMITED PARTNERS.......13
PART II.....................................................................13
ITEM 5. MARKET FOR THE REGISTRANT'S LIMITED PARTNERSHIP UNITS AND
RELATED LIMITED PARTNER MATTERS...........................13
ITEM 6. SELECTED FINANCIAL DATA...................................16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.................................18
ITEM 7A.....QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...............29
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE..................................52
PART III....................................................................52
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........52
ITEM 11. EXECUTIVE COMPENSATION....................................53
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT................................................58
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............58
PART IV.....................................................................60
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K..................................................60
SIGNATURES............................................................63
-2-
<PAGE>
PART I
ITEM 1 BUSINESS
General
The Dyco Oil and Gas Program 1979-1 Limited Partnership (the "1979-1
Program") and Dyco Oil and Gas Program 1979-2 Limited Partnership (the "1979-2
Program") (collectively, the "Programs") are Minnesota limited partnerships
engaged in the production of oil and gas. The 1979-1 Program and 1979-2 Program
commenced operations on April 2, 1979 and July 2, 1979, respectively, with the
primary financial objective of investing their limited partners' subscriptions
in the drilling of oil and gas prospects and then distributing to their limited
partners all available cash flow from the Program's on-going production
operations. Dyco Petroleum Corporation ("Dyco") serves as the General Partner of
the Programs. See "Item 2. Properties" for a description of the Programs'
reserves and properties.
The limited partnership agreements for each of the Programs (the "Program
Agreements") provide that limited partners are allocated 99% of all Program
costs and revenues and Dyco, as General Partner, is allocated 1% of all Program
costs and revenues. Included in such costs is each Program's reimbursement to
Dyco of the Program's proportionate share of Dyco's geological, engineering, and
general and administrative expenses.
Dyco currently serves as General Partner of 31 limited partnerships,
including the Programs. Dyco is a wholly-owned subsidiary of Samson Investment
Company. Samson Investment Company and its various corporate subsidiaries,
including Dyco, (collectively, "Samson") are primarily engaged in the production
and development of and exploration for oil and gas reserves and the acquisition
and operation of producing properties. At January 31, 1999, Samson owned
interests in approximately 10,500 oil and gas wells located in 19 states of the
United States and the countries of Canada, Venezuela, and Russia. At January 31,
1999, Samson operated approximately 2,900 oil and gas wells located in 15 states
of the United States, as well as Canada, Venezuela, and Russia.
As limited partnerships, the Programs have no officers, directors, or
employees. They rely instead on the personnel of Dyco and Samson. As of March 1,
1999 Samson employed approximately 900 persons. No employees are covered by
collective bargaining agreements, and management believes that Samson provides a
sound employee relations environment. For information regarding the executive
officers of Dyco, see "Item 10. Directors and Executive Officers of the
Registrant."
Dyco's and the Programs' principal place of business is located at Samson
Plaza, Two West Second Street, Tulsa, Oklahoma
-3-
<PAGE>
74103, and their telephone number is (918) 583-1791 or (800) 283-1791.
Funding
Although the Program Agreements permit the Programs to incur borrowings,
each Program's operations and expenses are currently funded out of each
Program's revenues from oil and gas sales. Dyco may, but is not required to,
advance funds to each of the Programs for the same purposes for which Program
borrowings are authorized.
Principal Products Produced and Services Rendered
The Programs' sole business is the development and production of oil and
gas with a concentration on gas. The Programs do not hold any patents,
trademarks, licenses, or concessions and are not a party to any government
contracts. The Programs have no backlog of orders and do not participate in
research and development activities. The Programs are not presently encountering
shortages of oilfield tubular goods, compressors, production material, or other
equipment.
Oil, Gas, and Environmental Control Regulations
Regulation of Production Operations -- The production of oil and gas is
subject to extensive federal and state laws and regulations governing a wide
variety of matters, including the drilling and spacing of wells, allowable rates
of production, prevention of waste and pollution, and protection of the
environment. In addition to the direct costs borne in complying with such
regulations, operations and revenues may be impacted to the extent that certain
regulations limit oil and gas production to below economic levels.
Regulation of Sales and Transportation of Oil and Gas -- Sales of crude
oil and condensate are made by the Programs at market prices and are not subject
to price controls. The sale of gas may be subject to both federal and state laws
and regulations. The provisions of these laws and regulations are complex and
affect all who produce, resell, transport, or purchase gas, including the
Programs. Although virtually all of the Programs' gas production is not subject
to price regulation, other regulations affect the availability of gas
transportation services and the ability of gas consumers to continue to purchase
or use gas at current levels. Accordingly, such regulations may have a material
effect on the Programs' operations and projections of future oil and gas
production and revenues.
Future Legislation -- Legislation affecting the oil and gas industry is
under constant review for amendment or expansion.
-4-
<PAGE>
Because such laws and regulations are frequently amended or reinterpreted,
management is unable to predict what additional energy legislation may be
proposed or enacted or the future cost and impact of complying with existing or
future regulations.
Regulation of the Environment -- The Programs' operations are subject to
numerous laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Compliance with
such laws and regulations, together with any penalties resulting from
noncompliance, may increase the cost of the Programs' operations or may affect
the Programs' ability to timely complete existing or future activities.
Management anticipates that various local, state, and federal environmental
control agencies will have an increasing impact on oil and gas operations.
Significant Customers
Purchases of gas by El Paso Energy Marketing Company ("El Paso") and Enron
Oil and Gas Company accounted for approximately 79.1% and 18.6%, respectively,
of the 1979-1 Program's oil and gas sales during the year ended December 31,
1998. With respect to the 1979-2 Program, purchases of gas by El Paso accounted
for approximately 74.6% of its oil and gas sales during the year ended December
31, 1998. In the event of interruption of purchases by these significant
customers or the cessation or material change in availability of open-access
transportation by the Programs' pipeline transporters, the Programs may
encounter difficulty in marketing their gas and in maintaining historic sales
levels. Alternative purchasers or transporters may not be readily available.
The Programs' principal customers for crude oil production are refiners
and other companies which have pipeline facilities near the producing properties
of the Programs. In the event pipeline facilities are not conveniently available
to production areas, crude oil is usually trucked by purchasers to storage
facilities.
Competition and Marketing
The domestic oil and gas industry is highly competitive, with a large
number of companies and individuals engaged in the exploration and development
of oil and gas properties. The ability of the Programs to produce and market oil
and gas profitably depends on a number of factors that are beyond the control of
the Programs. These factors include worldwide political instability (especially
in oil-producing regions), United Nations export embargoes, the supply and price
of foreign imports of oil and gas, the level of consumer product demand (which
can be heavily influenced by weather patterns), government regulations and
taxes, the price and availability of alternative
-5-
<PAGE>
fuels, the overall economic environment, and the availability and capacity of
transportation and processing facilities. In addition, on March 12, 1999 several
major oil producing nations agreed to curtail oil exports in an effort to
increase worldwide oil prices. The effect of these factors on future oil and gas
industry trends cannot be accurately predicted or anticipated.
The most important variable affecting the Programs' revenues is the prices
received for the sale of oil and gas. Predicting future prices is not possible.
Concerning past trends, average yearly wellhead gas prices in the United States
have been volatile for a number of years. For the past ten years, such average
prices have generally been in the $1.40 to $2.40 per Mcf range.
Substantially all of the Programs' gas reserves are being sold on the
"spot market." Prices on the spot market are subject to wide seasonal and
regional pricing fluctuations due to the highly competitive nature of the spot
market. In addition, such spot market sales are generally short-term in nature
and are dependent upon the obtaining of transportation services provided by
pipelines. Spot prices for the Programs' gas decreased from approximately $2.32
per Mcf at December 31, 1997 to approximately $1.93 per Mcf at December 31,
1998. Such prices were on an MMBTU basis and differ from the prices actually
received by the Programs due to transportation and marketing costs, BTU
adjustments, and regional price and quality differences. Continued very low oil
prices as discussed below may cause downward pressure on gas prices due to some
users of gas converting to oil as a cheaper fuel alternative.
For the past ten years, average oil prices have generally been in the
$16.00 to $24.00 per barrel range. Due to global consumption and supply trends
over the last year as well as at least a short-term slowdown in Asian energy
demand, oil prices over the past year have reached historically low levels,
dropping to as low as approximately $9.00 per barrel. It is not known whether
this trend will continue. Prices for the Programs' oil decreased from
approximately $16.25 per barrel at December 31, 1997 to approximately $9.50 per
barrel at December 31, 1998.
As of February 28, 1999 oil and gas prices were approximately $9.50 per
barrel and $1.55 per Mcf, respectively. Future prices for both oil and gas will
likely be different from (and may be lower than) the prices in effect on
December 31, 1998 and February 28, 1999. As of the date of this Annual Report,
oil prices have increased slightly over the February 28, 1999 price, primarily
due to the March 1999 announcement that several oil producing nations intend to
curtail oil exports. Management is unable to predict whether future oil and gas
prices will (i) stabilize, (ii) increase, or (iii) decrease.
-6-
<PAGE>
Insurance Coverage
The Programs are subject to all of the risks inherent in the exploration
for and production of oil and gas, including blowouts, pollution, fires, and
other casualties. The Programs maintain insurance coverage as is customary for
entities of a similar size engaged in operations similar to that of the
Programs, but losses can occur from uninsurable risks or in amounts in excess of
existing insurance coverage. The occurrence of an event which is not fully
covered by insurance could have a material adverse effect on the Programs'
financial condition and results of operations.
ITEM 2 PROPERTIES
Well Statistics
The following table sets forth the numbers of gross and net productive
wells of the Programs as of December 31, 1998.
Well Statistics(1)
As of December 31, 1998
1979-1 1979-2
Program Program
------- -------
Gross productive wells(2):
Oil 2 -
Gas 25 18
-- --
Total 27 18
Net productive wells(3):
Oil .08 -
Gas 1.13 1.50
---- ----
Total 1.21 1.50
- ---------------
(1) The designation of a well as an oil well or gas well is made by Dyco based
on the relative amount of oil and gas reserves for the well. Regardless of
a well's oil or gas designation, it may produce oil, gas, or both oil and
gas.
(2) As used throughout this Annual Report on Form 10-K ("Annual Report"),
"Gross Well" refers to a well in which a working interest is owned. The
number of gross wells is the total number of wells in which a working
interest is owned.
(3) As used throughout this Annual Report, "Net Well" refers to the sum of the
fractional working interests owned in gross wells. For example, a 15%
working interest in a well represents one Gross Well, but 0.15 Net Well.
-7-
<PAGE>
Drilling Activities
The 1979-1 Program participated in no drilling activities for the year
ended December 31, 1998, while the 1979-2 Program indirectly participated in
drilling the Elliot No. 4-16 Well in Custer County, Oklahoma. The 1979-2 Program
has a .0006 revenue interest in this producing gas well. The 1979-2 Program does
not own a working interest in this well; therefore, it did not incur any costs
associated with this drilling activity.
Oil and Gas Production, Revenue, and Price History
The following table sets forth certain historical information concerning
the oil (including condensates) and gas production, net of all royalties,
overriding royalties, and other third party interests, of the Programs, revenues
attributable to such production, and certain price and cost information.
Net Production Data
Year Ended December 31,
--------------------------------------
1998 1997 1996
---------- --------- --------
1979-1 Program:
- --------------
Production:
Oil (Bbls)(1) 291 366 378
Gas (Mcf)(2) 185,215 205,089 238,389
Oil and gas sales:
Oil $ 4,242 $ 7,208 $ 8,094
Gas 337,457 461,659 492,114
------- ------- -------
Total $341,699 $468,867 $500,208
======= ======= =======
Total direct operating
expenses (3) $ 72,099 $ 87,871 $103,193
======= ======= =======
Direct operating expenses as
a percentage of oil and
gas sales 21.1% 18.7% 20.6%
Average sales price:
Per barrel of oil $14.58 $19.69 $21.42
Per Mcf of gas 1.82 2.25 2.06
Direct operating expenses
per equivalent Mcf of
gas(4) $ .39 $ .42 $ .43
-8-
<PAGE>
Year Ended December 31,
----------------------------------------
1998 1997 1996
---------- --------- ----------
1979-2 Program:
- --------------
Production:
Oil (Bbls)(1) 1,067 1,325 1,336
Gas (Mcf)(2) 191,087 265,409 296,244
Oil and gas sales:
Oil $ 14,380 $ 26,891 $ 28,156
Gas 422,747 669,037 700,890
------- ------- -------
Total $437,127 $695,928 $729,046
======= ======= =======
Total direct operating
expenses(3) $113,900 $127,516 $147,342
======= ======= =======
Direct operating expenses as
a percentage of oil and
gas sales 26.1% 18.3% 20.2%
Average sales price:
Per barrel of oil $13.48 $20.30 $21.07
Per Mcf of gas 2.21 2.52 2.37
Direct operating expenses
per equivalent Mcf of
gas(4) $ .58 $ .47 $ .48
- ---------------
(1) As used throughout this Annual Report, "Bbls" refers to barrels of 42 U.S.
gallons and represents the basic unit for measuring the production of
crude oil and condensate oil.
(2) As used throughout this Annual Report, "Mcf" refers to volume of 1,000
cubic feet under prescribed conditions of pressure and temperature and
represents the basic unit for measuring the production of gas.
(3) Includes lease operating expenses and production taxes.
(4) Oil production is converted to gas equivalents at the rate of six Mcf per
barrel, representing the estimated relative energy content of gas and oil,
which rate is not necessarily indicative of the relationship of oil and
gas prices. The respective prices of oil and gas are affected by market
and other factors in addition to relative energy content.
Proved Reserves and Net Present Value
The following table sets forth the Programs' estimated proved oil and gas
reserves and net present value therefrom as of
-9-
<PAGE>
December 31, 1998. The schedule of quantities of proved oil and gas reserves was
prepared by Dyco in accordance with the rules prescribed by the Securities and
Exchange Commission (the "SEC"). As used throughout this Annual Report, "proved
reserves" refers to those estimated quantities of crude oil, gas, and gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known oil and gas reservoirs
under existing economic and operating conditions.
Net present value represents estimated future gross cash flow from the
production and sale of proved reserves, net of estimated oil and gas production
costs (including production taxes, ad valorem taxes, and operating expenses),
and estimated future development costs, discounted at 10% per annum. Net present
value attributable to the Programs' proved reserves was calculated on the basis
of current costs and prices at December 31, 1998. Such prices were not escalated
except in certain circumstances where escalations were fixed and readily
determinable in accordance with applicable contract provisions. The prices used
by Dyco in calculating the net present value attributable to the Programs'
proved reserves do not necessarily reflect market prices for oil and gas
production subsequent to December 31, 1998. There can be no assurance that the
prices used in calculating the net present value of the Programs' proved
reserves at December 31, 1998 will actually be realized for such production.
The process of estimating oil and gas reserves is complex, requiring
significant subjective decisions in the evaluation of available geological,
engineering, and economic data for each reservoir. The data for a given
reservoir may change substantially over time as a result of, among other things,
additional development activity, production history, and viability of production
under varying economic conditions; consequently, it is reasonably possible that
material revisions to existing reserve estimates may occur in the near future.
Although every reasonable effort has been made to ensure that these reserve
estimates represent the most accurate assessment possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
-10-
<PAGE>
Proved Reserves and
Net Present Value
From Proved Reserves
As of December 31, 1998
1979-1 Program:
- --------------
Estimated proved reserves:
Gas (Mcf) 1,045,294
Oil and liquids (Bbls) 1,697
Net present value (discounted at 10%
per annum) $ 852,390
1979-2 Program:
- --------------
Estimated proved reserves:
Gas (Mcf) 1,023,297
Oil and liquids (Bbls) 11,871
Net present value (discounted at 10%
per annum) $ 919,886
No estimates of the proved reserves of the Programs comparable to those
included herein have been included in reports to any federal agency other than
the SEC. Additional information relating to the Programs' proved reserves is
contained in Note 4 to the Programs' financial statements, included in Item 8 of
this Annual Report.
Significant Properties
1979-1 Program
--------------
As of December 31, 1998, the 1979-1 Program's properties consisted of 27
gross (1.21 net) productive wells. The 1979-1 Program also owned a non-working
interest in an additional 8 wells. Affiliates of the 1979-1 Program operate 12
(34%) of its total wells. All of the 1979-1 Program's reserves are located in
the Anadarko Basin of western Oklahoma and the Texas panhandle, which is an
established oil and gas producing basin.
-11-
<PAGE>
1979-2 Program
--------------
As of December 31, 1998, the 1979-2 Program's properties consisted of 18
gross (1.50 net) productive wells. The 1979-2 Program also owned a non-working
interest in an additional two wells. Affiliates of the 1979-2 Program operate 5
(25%) of its wells. All of the 1979-2 Program's properties are located onshore
in the continental United States. Substantially all of the 1979-2 Program's
reserves are located in the Anadarko Basin.
As of December 31, 1998, the 1979-2 Program's properties in the Anadarko
Basin consisted of 13 gross (1.20 net) productive wells. The 1979-2 Program also
owned a non-working interest in an additional 2 wells in the Anadarko Basin.
Affiliates of the 1979-2 Program operate 4 (27%) of its Anadarko Basin wells. As
of December 31, 1998, the 1979-2 Program had estimated total proved reserves in
the Anadarko Basin of approximately 993,057 Mcf of gas and approximately 11,871
barrels of crude oil, with a present value (discounted at 10% per annum) of
estimated future net cash flow of approximately $883,091.
Title to Oil and Gas Properties
Management believes that the Programs have satisfactory title to their oil
and gas properties. Record title to substantially all of the Programs'
properties is held by Dyco as nominee.
Title to the Programs' properties is subject to customary royalty,
overriding royalty, carried, working, and other similar interests and
contractual arrangements customary in the oil and gas industry, to liens for
current taxes not yet due, and to other encumbrances. Management believes that
such burdens do not materially detract from the value of such properties or from
the Programs' interest therein or materially interfere with their use in the
operation of the Programs' business.
ITEM 3. LEGAL PROCEEDINGS
On October 24, 1996, certain royalty owners filed a class action lawsuit
against Dyco and certain other parties in which they alleged entitlement to a
share of the proceeds from a gas contract involving one of the 1979-2 Program's
wells, the Maxwell No. 1-23. (Thurman Horn, et al., v. Dyco, et al., Case No.
10,324, District Court of Wheeler County, Texas). The 1979-2 Program has a 22.5%
working interest in the Maxwell No. 1-23. The plaintiffs are alleging causes of
action based on breach of duty to market, breach of duty to pay royalties, and
breach of duty of good faith and fair dealing and are seeking restitution and an
accounting. The Plaintiffs have not quantified the amount of their damages. Dyco
has filed its answer in the matter in
-12-
<PAGE>
which it denied all of the plaintiffs' allegations, and discovery is proceeding
in the matter. On November 24, 1998 Dyco filed a motion for summary judgment in
the matter. Dyco intends to vigorously defend the lawsuit. As of the date of
this Annual Report, management cannot determine the amount of any alleged
damages which would be allocable to the 1979-2 Program from this lawsuit. A
Texas appellate court has previously ruled in a separate lawsuit that owners of
royalty interests in Texas oil and gas properties do not have the right to share
in the proceeds of take-or-pay settlements.
On February 25, 1998, Randy Beutler filed a lawsuit against Dyco alleging
that Dyco amended or terminated certain gas purchase contracts and fraudulently
concealed the settlement of these contracts. (Randy Beutler, et al. v. Dyco
Petroleum Corporation, CJ-98-16, District Court of Beckham County, Oklahoma.)
The plaintiff has filed the petition as a class action on behalf of all
individuals who leased Oklahoma mineral leases to Dyco which were subject to
certain gas purchase contracts. The plaintiff alleges that Dyco's actions
resulted in a breach of the express and implied obligations of the leases and
reckless indifference and/or actual fraud on behalf of Dyco. Dyco has filed its
answer in the matter in which it denied all of the plaintiffs' allegations. As
of the date of this Annual Report, Dyco has not determined what wells are
subject to this lawsuit; however, the proposed class action representative is a
lessor in the Johnson No. 1-22 well. The 1979-2 Program has an approximate 2.6%
working interest in this well. Dyco intends to vigorously defend this lawsuit.
Except for the foregoing, to the knowledge of the management of Dyco and
the Programs, neither Dyco, the Programs, nor the Programs' properties are
subject to any litigation, the results of which would have a material effect on
the Programs' or Dyco's financial condition or operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF LIMITED PARTNERS
There were no matters submitted to a vote of the limited partners of
either Program during 1998.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S LIMITED PARTNERSHIP UNITS AND
RELATED LIMITED PARTNER MATTERS
The Programs do not have an established trading market for their units of
limited partnership interest ("Units"). Pursuant to the terms of the Program
Agreements, Dyco, as General Partner, is obligated to annually issue a
repurchase offer which is based on the estimated future net revenues from the
Programs' reserves and is calculated pursuant to the terms of the Program
-13-
<PAGE>
Agreements. Such repurchase offer is recalculated monthly in order to reflect
cash distributions made to the limited partners and extraordinary events. The
following table sets forth, for the periods indicated, Dyco's repurchase offer
per Unit and the amount of the Programs' cash distributions per Unit for the
same period. For purposes of this Annual Report, a Unit represents an initial
subscription of $5,000 to a Program.
1979-1 Program
--------------
Repurchase Cash
Price Distributions
---------- -------------
1997:
First Quarter $230 $35
Second Quarter 195 40
Third Quarter 299 20
Fourth Quarter 217 20
1998:
First Quarter $197 $35
Second Quarter 162 70(1)
Third Quarter 203 40
Fourth Quarter 163 -
1999:
First Quarter $163 $20(2)
- --------------
(1) Includes proceeds from the sale of oil and gas properties.
(2) Distribution will be paid March 25, 1999.
-14-
<PAGE>
1979-2 Program
--------------
Repurchase Cash
Price Distributions
---------- -------------
1997:
First Quarter $210 $55
Second Quarter 155 50
Third Quarter 284 50
Fourth Quarter 184 55
1998:
First Quarter $129 $35
Second Quarter 94 35
Third Quarter 358 60
Fourth Quarter 298 20
1999:
First Quarter $278 $ -
As of March 1, 1999, the 1979-1 Program has 3,140 Units outstanding and
approximately 1,050 Limited Partners of record. The 1979-2 Program has 2,860
Units outstanding and approximately 800 Limited Partners of record.
-15-
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The following tables present selected financial data for the Programs. This
data should be read in conjunction with the financial statements of the
Programs, and the respective notes thereto, included elsewhere in this Annual
Report. See "Item 8. Financial Statements and Supplementary Data."
<TABLE>
<CAPTION>
1979-1 Program
--------------
December 31,
------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Summary of Operations:
Oil and gas sales $341,699 $468,867 $500,208 $396,493 $400,698
Total revenues 491,495 471,940 502,561 398,559 401,930
Lease operating expenses 47,169 55,138 67,719 90,080 52,310
Production taxes 24,930 32,733 35,474 28,290 29,007
General and administrative
expenses 52,637 55,701 54,220 54,317 51,498
Depreciation, depletion, and
amortization of oil and gas
properties 24,232 39,290 33,690 54,252 70,054
Net income 342,527 289,078 311,458 171,620 199,061
per Unit 107.98 91.13 98.19 54.10 62.76
Cash distributions 459,940 364,780 317,200 206,180 237,900
per Unit 145 115 100 65 75
Summary Balance Sheet Data:
Total assets 247,907 368,032 453,642 467,816 483,352
Partners' capital 210,710 328,123 403,825 409,567 444,127
</TABLE>
-16-
<PAGE>
<TABLE>
<CAPTION>
1979-2 Program
--------------
December 31,
---------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Summary of Operations:
Oil and gas sales $437,127 $695,928 $729,046 $483,467 $1,017,344
Total revenues 445,030 705,215 735,326 490,205 1,025,628
Lease operating expenses 83,351 75,640 94,195 67,295 178,826
Production taxes 30,549 51,876 53,147 36,662 74,862
General and administrative
expenses 38,742 41,613 40,363 40,709 37,993
Depreciation, depletion,
and amortization of oil
and gas properties 49,082 77,495 71,807 84,448 244,687
Net income 243,306 458,591 475,814 261,091 489,260
per Unit 84.22 158.74 164.70 90.37 169.35
Cash distributions 433,350 606,690 491,130 447,795 476,685
per Unit 150 210 170 155 165
Summary Balance Sheet Data:
Total assets 414,072 559,776 709,662 705,367 857,507
Partners' capital 309,132 499,176 647,275 662,591 849,295
</TABLE>
-17-
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Use of Forward-Looking Statements and Estimates
This Annual Report contains certain forward-looking statements. The words
"anticipate," "believe," "expect," "plan," "intend," "estimate," "project,"
"could," "may," and similar expressions are intended to identify forward-looking
statements. Such statements reflect management's current views with respect to
future events and financial performance. This Annual Report also includes
certain information which is, or is based upon, estimates and assumptions. Such
estimates and assumptions are management's efforts to accurately reflect the
condition and operation of the Programs.
Use of forward-looking statements and estimates and assumptions involve
risks and uncertainties which include, but are not limited to, the volatility of
oil and gas prices, the uncertainty of reserve information, the operating risk
associated with oil and gas properties (including the risk of personal injury,
death, property damage, damage to the well or producing reservoir, environmental
contamination, and other operating risks), the prospect of changing tax and
regulatory laws, the availability and capacity of processing and transportation
facilities, the general economic climate, the supply and price of foreign
imports of oil and gas, the level of consumer product demand, and the price and
availability of alternative fuels. Should one or more of these risks or
uncertainties occur or should estimates or underlying assumptions prove
incorrect, actual conditions or results may vary materially and adversely from
those stated, anticipated, believed, estimated, or otherwise indicated.
General Discussion
The following general discussion should be read in conjunction with the
analysis of results of operations provided below. The most important variable
affecting the Programs' revenues is the prices received for the sale of oil and
gas. Predicting future prices is not possible. Concerning past trends, average
yearly wellhead gas prices in the United States have been volatile for a number
of years. For the past ten years, such average prices have generally been in the
$1.40 to $2.40 per Mcf range.
Substantially all of the Programs' gas reserves are being sold on the
"spot market." Prices on the spot market are subject to wide seasonal and
regional pricing fluctuations due to the highly competitive nature of the spot
market. In addition, such spot market sales are generally short-term in nature
and are dependent upon the obtaining of transportation services provided by
pipelines. Spot prices for the Programs' gas decreased from
-18-
<PAGE>
approximately $2.32 per Mcf at December 31, 1997 to approximately $1.93 per Mcf
at December 31, 1998. Such prices were on an MMBTU basis and differ from the
prices actually received by the Programs due to transportation and marketing
costs, BTU adjustments, and regional price and quality differences. Continued
very low oil prices as discussed below may cause downward pressure on gas prices
due to some users of gas converting to oil as a cheaper fuel alternative.
For the past ten years, average oil prices have generally been in the
$16.00 to $24.00 per barrel range. Due to global consumption and supply trends
over the last year as well as at least a short-term slowdown in Asian energy
demand, oil prices over the past year have reached historically low levels,
dropping to as low as approximately $9.00 per barrel. It is not known whether
this trend will continue. Prices for the Programs' oil decreased from
approximately $16.25 per barrel at December 31, 1997 to approximately $9.50 per
barrel at December 31, 1998.
As of February 28, 1999 oil and gas prices were approximately $9.50 per
barrel and $1.55 per Mcf, respectively. Future prices for both oil and gas will
likely be different from (and may be lower than) the prices in effect on
December 31, 1998 and February 28, 1999. As of the date of this Annual Report,
oil prices have increased slightly over the February 28, 1999 price, primarily
due to the March 1999 announcement that several oil producing nations intend to
curtail oil exports. Management is unable to predict whether future oil and gas
prices will (i) stabilize, (ii) increase, or (iii) decrease.
Results of Operations
1979-1 Program
--------------
Year Ended December 31, 1998 Compared to
Year Ended December 31, 1997
----------------------------------------
Total oil and gas sales decreased $127,168 (27.1%) in 1998 as compared to
1997. Of this decrease, approximately $45,000 was related to a decrease in
volumes of gas sold and approximately $79,000 was related to a decrease in the
average price of gas sold. Volumes of oil and gas sold decreased 75 barrels and
19,874 Mcf, respectively, in 1998 as compared to 1997. The decrease in volumes
of gas sold resulted primarily from the sale of several wells in 1997 and 1998
and normal declines in production. These decreases were partially offset by a
positive prior period volume adjustment made in 1998 by the purchaser on one
well. Average oil and gas prices decreased to $14.58 per barrel and $1.82 per
Mcf, respectively, in 1998 from $19.69 per barrel and $2.25 per Mcf,
respectively, 1997.
-19-
<PAGE>
As discussed in "Liquidity and Capital Resources" below, the 1979-1
Program sold several wells during the first quarter of 1998 for $162,007
representing approximately 9% of its total reserves. The proceeds from these
sales would have reduced the net book value of the oil and gas properties by
90%, significantly altering the 1979-1 Program's capitalized cost/proved
reserves relationship. Accordingly, capitalized costs were reduced by
approximately 9% and a gain on sale of oil and gas properties of $145,376 was
recognized. Similar sales during 1997 did not significantly alter the 1979-1
Program's capitalized cost/proved reserves relationship.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $15,772 (17.9%) in 1998 as compared to 1997. This
decrease resulted primarily from decreases in (i) production taxes associated
with the decrease in oil and gas sales and (ii) lease operating expenses
associated with the decrease in volumes of oil and gas sold. As a percentage of
oil and gas sales, these expenses increased to 21.1% in 1998 from 18.7% in 1997.
This percentage increase was primarily due to the decreases in the average
prices of oil and gas sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $15,058 (38.3%) in 1998 as compared to 1997. This decrease resulted
primarily from (i) the decrease in volumes of oil and gas sold, (ii) the sale of
several wells in 1998 which decreased the amortizable capitalized costs of the
oil and gas properties, and (iii) upward revisions in the estimates of remaining
oil and gas reserves as of December 31, 1998. As a percentage of oil and gas
sales, this expense decreased to 7.1% in 1998 from 8.4% in 1997. This percentage
decrease was primarily due to the dollar decrease in depreciation, depletion,
and amortization, which decrease was partially offset by the decreases in the
average prices of oil and gas sold.
General and administrative expenses decreased $3,064 (5.5%) in 1998 as
compared to 1997. As a percentage of oil and gas sales, these expenses increased
to 15.4% in 1998 from 11.9% in 1997. This percentage increase was primarily due
to the decrease in oil and gas sales.
Year Ended December 31, 1997 Compared to
Year Ended December 31, 1996
----------------------------------------
Total oil and gas sales decreased $31,341 (6.3%) in 1997 as compared to
1996. Of this decrease, approximately $69,000 was related to a decrease in
volumes of gas sold, which decrease was partially offset by an increase of
approximately $39,000 related to an increase in the average price of gas sold.
Volumes of oil
-20-
<PAGE>
and gas sold decreased 12 barrels and 33,300 Mcf, respectively, in 1997 as
compared to 1996. The decrease in volumes of gas sold resulted primarily from
(i) negative prior period volume adjustments in 1997 made by the purchaser on
one well, (ii) normal declines in production, and (iii) positive prior period
volume adjustments in 1996 made by the purchaser on one well. Average oil prices
decreased to $19.69 per barrel in 1997 from $21.42 per barrel in 1996. Average
gas prices increased to $2.25 per Mcf in 1997 from $2.06 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $15,322 (14.8%) in 1997 as compared to 1996. This
decrease resulted primarily from the decreases in volumes of oil and gas sold in
1997 and a decrease in production taxes associated with the decrease in oil and
gas sales. As a percentage of oil and gas sales, these expenses decreased to
18.7% in 1997 from 20.6% in 1996. This percentage decrease was primarily due to
the increase in the average price of gas sold in 1997.
Depreciation, depletion, and amortization of oil and gas properties
increased $5,600 (16.6%) in 1997 as compared to 1996. This increase resulted
primarily from decreases in prices used to value oil and gas reserves in 1997 as
compared to 1996, which decrease was partially offset by the decreases in
volumes of oil and gas sold in 1997. As a percentage of oil and gas sales, this
expense increased to 8.4% in 1997 from 6.7% in 1996. This percentage increase
was primarily due to the dollar increase in depreciation, depletion, and
amortization.
General and administrative expenses increased $1,481 (2.7%) in 1997 as
compared to 1996. As a percentage of oil and gas sales, these expenses increased
to 11.9% in 1997 from 10.8% in 1996. This percentage increase was primarily due
to the decrease in oil and gas sales.
1979-2 Program
--------------
Year Ended December 31, 1998 Compared to
Year Ended December 31, 1997
----------------------------------------
Total oil and gas sales decreased $258,801 (37.2%) in 1998 as compared to
1997. Of this decrease, approximately $187,000 was related to a decrease in
volumes of gas sold and approximately $59,000 was related to a decrease in the
average price of gas sold. Volumes of oil and gas sold decreased 258 barrels and
74,322 Mcf, respectively, in 1998 as compared to 1997. The decrease in volumes
of gas sold resulted primarily from (i) the curtailment of sales in 1998 on one
well due to the 1979-2 Program's overproduced position in that well and (ii)
normal declines in production. Average oil and gas prices
-21-
<PAGE>
decreased to $13.48 per barrel and $2.21 per Mcf, respectively, in 1998 from
$20.30 per barrel and $2.52 per Mcf, respectively, in 1997.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $13,616 (10.7%) in 1998 as compared to 1997. This
decrease was primarily due to a decrease in production taxes associated with the
decrease in oil and gas sales, which decrease was partially offset by an
increase in lease operating expenses primarily due to the settlement of a
lawsuit during 1998. As a percentage of oil and gas sales, these expenses
increased to 26.1% in 1998 from 18.3% in 1997. This percentage increase was
primarily due to the decreases in the average prices of oil and gas sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $28,413 (36.7%) in 1998 as compared to 1997. This decrease resulted
primarily from the decreases in volumes of oil and gas sold. As a percentage of
oil and gas sales, this expense remained relatively constant at 11.2% in 1998
and 11.1% in 1997.
General and administrative expenses decreased $2,871 (6.9%) in 1998 as
compared to 1997. As a percentage of oil and gas sales, these expenses increased
to 8.9% in 1998 from 6.0% in 1997. This percentage increase was primarily due to
the decrease in oil and gas sales.
Year Ended December 31, 1997 Compared to
Year Ended December 31, 1996
----------------------------------------
Total oil and gas sales decreased $33,118 (4.5%) in 1997 as compared to
1996. Of this decrease, approximately $73,000 was related to a decrease in
volumes of gas sold, which decrease was partially offset by an increase of
approximately $40,000 related to an increase in the average price of gas sold.
Volumes of oil and gas sold decreased 11 barrels and 30,835 Mcf, respectively,
in 1997 as compared to 1996. The decrease in volumes of gas sold resulted
primarily from negative prior period volume adjustments made by the purchasers
on two wells in 1997. Average oil prices decreased to $20.30 per barrel in 1997
from $21.07 per barrel in 1996. Average gas prices increased to $2.52 per Mcf in
1997 from $2.37 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $19,826 (13.5%) in 1997 as compared to 1996. This
decrease resulted primarily from (i) the decreases in volumes of oil and gas
sold in 1997, (ii) decreased general operating expenses on one well in 1997 as
compared to 1996, and (iii) decreased compression expenses on two wells in 1997
as compared to 1996. As a percentage of oil and gas sales, these expenses
decreased to 18.3% in 1997 from 20.2%
-22-
<PAGE>
in 1996. This percentage decrease was primarily due to the increase in the
average price of gas sold in 1997.
Depreciation, depletion, and amortization of oil and gas properties
increased $5,688 (7.9%) in 1997 as compared to 1996. This increase resulted
primarily from decreases in prices used to value oil and gas reserves in 1997 as
compared to 1996, which decrease was partially offset by the decreases in
volumes of oil and gas sold in 1997. As a percentage of oil and gas sales, this
expense increased to 11.1% in 1997 from 9.8% in 1996. This percentage increase
was primarily due to the dollar increase in depreciation, depletion, and
amortization.
General and administrative expenses increased $1,250 (3.1%) in 1997 as
compared to 1996. As a percentage of oil and gas sales, these expenses remained
relatively constant at 6.0% in 1997 and 5.5% in 1996.
Liquidity and Capital Resources
Net proceeds from operations less necessary operating capital are
distributed to the limited partners on a quarterly basis. See "Item 5. Market
for the Registrant's Limited Partnership Units and Related Limited Partner
Matters." The net proceeds from production are not reinvested in productive
assets, except to the extent that producing wells are improved, or where methods
are employed to permit more efficient recovery of reserves, thereby resulting in
a positive economic impact. Assuming 1998 production levels for future years,
the 1979-1 Program's proved reserve quantities at December 31, 1998 would have
remaining lives of approximately 5.6 years for gas reserves and 5.8 years for
oil reserves and the 1979-2 Program's proved oil and gas reserve quantities at
December 31, 1998 would have remaining lives of approximately 5.4 years for gas
reserves and 11.1 years for oil reserves. However, since the Programs' reserve
estimates are based on oil and gas prices at December 31, 1998, it is possible
that a significant decrease in oil and gas prices from December 31, 1998 levels
will reduce such reserves and their corresponding life-span.
The Programs' available capital from the limited partners' subscriptions
has been spent on oil and gas drilling activities and there should be no further
material capital resource commitments in the future. Occasional expenditures by
the Programs for well completions or workovers, however, may reduce or eliminate
cash available for a particular quarterly cash distribution. The Programs have
no debt commitments. Cash for operational purposes will be provided by current
oil and gas production.
The 1979-1 Program's Statement of Cash Flows for the year ended December
31, 1998 includes proceeds from the sale of oil and gas properties during 1998.
It is possible that the 1979-1
-23-
<PAGE>
Program's repurchase values and future cash distributions could decline as a
result of the disposition of these properties. On the other hand, the General
Partner believes there will be beneficial operating efficiencies related to the
1979-1 Program's remaining properties. This is primarily due to the fact that
the properties sold generally bore a higher ratio of operating expenses as
compared to reserves than the 1979-1 Program's remaining properties.
There can be no assurance as to the amount of the Programs' future cash
distributions. The Programs' ability to make cash distributions depends
primarily upon the level of available cash flow generated by the Programs'
operating activities, which will be affected (either positively or negatively)
by many factors beyond the control of the Programs, including the price of and
demand for oil and gas and other market and economic conditions. Even if prices
and costs remain stable, the amount of cash available for distributions will
decline over time (as the volume of production from producing properties
declines) since the Programs are not replacing production through acquisitions
of producing properties and drilling.
Inflation and Changing Prices
Prices obtained for oil and gas production depend upon numerous factors,
including the extent of domestic and foreign production, foreign imports of oil,
market demand, domestic and foreign economic conditions in general, and
governmental regulations and tax laws. The general level of inflation in the
economy did not have a material effect on the operations of the Program in 1998.
Oil and gas prices have fluctuated during recent years and generally have not
followed the same pattern as inflation. See "Item 2. Properties Oil and Gas
Production, Revenue, and Price History."
Year 2000 Computer Issues
In General
The Year 2000 Issue ("Y2K") refers to the inability of computer and other
information technology systems to properly process date and time information,
stemming from the earlier programming practice of using two digits rather than
four to represent the year in a date. For example, computer programs and
imbedded chips that are date sensitive may recognize a date using (00) as the
year 1900 rather than the year 2000. The consequence of Y2K is that computer and
imbedded processing systems may be at risk of malfunctioning, particularly
during the transition from 1999 to 2000.
The effects of Y2K are exacerbated by the interdependence of computer and
telecommunication systems throughout the world.
-24-
<PAGE>
This interdependence also exists among the Programs, Samson, and their vendors,
customers, and business partners, as well as with regulators. The potential
risks associated with Y2K for an oil and gas production company fall into three
general areas: (i) financial, leasehold and administrative computer systems,
(ii) imbedded systems in field process control units, and (iii) third party
exposures. As discussed below, Dyco does not believe that these risks will be
material to the Programs' operations.
The Programs' business is producing oil and gas. The day-to-day production
of the Programs' oil and gas is not dependent on computers or equipment with
imbedded chips. As further discussed below, management anticipates that the
Programs' daily business activities will not be materially affected by Y2K.
The Programs rely on Samson to provide all of its operational and
administrative services on either a direct or indirect basis. Samson is
addressing each of the three Y2K areas discussed above through a readiness
process that seeks to:
1. increase the awareness of the issue among key employees;
2. identify areas of potential risk;
3. assess the relative impact of these risks and Samson's ability to
manage them; and
4. remediate these risks on a priority basis wherever possible.
Samson Investment Company's Chief Financial Officer is responsible for
communicating to its Board of Directors Y2K actions and for the ultimate
implementation of its Y2K plan. He has delegated to Samson Investment Company's
Senior Vice President-Technology and Administrative Services principal
responsibility for ensuring Y2K compliance within Samson.
Samson has been planning for the impact of Y2K on its information
technology systems since 1993. As of March 1, 1999, Samson is in the final
stages of implementation of a Y2K plan, as summarized below:
Financial and Administrative Systems
1. Awareness. Samson has alerted its officers, managers and supervisors of
Y2K issues and asked them to have their employees participate in the
identification of potential Y2K risks which might otherwise go unnoticed by
higher level employees and officers. As a result, awareness of the issue is
considered high.
2. Risk Identification. Samson's most significant financial and
administrative systems exposure is the Y2K status of the accounting and land
administration system used to collect and manage data for internal management
decision making and for
-25-
<PAGE>
external revenue and accounts payable purposes. Other concerns include network
hardware and software, desktop computing hardware and software,
telecommunications, and office space readiness.
3. Risk Assessment. The failure to identify and correct a material Y2K
problem could result in inaccurate or untimely financial information for
management decision-making or cash flow and payment purposes, including
maintaining oil and gas leases.
4. Remediation. Since 1993, Samson has been upgrading its accounting and
land administration software. Substantially all of the Y2K upgrades have been
completed, with the remainder scheduled to be completed during the 2nd quarter
of 1999. In addition, in 1997 and 1998 Samson replaced or applied software
patches to substantially all of its network and desktop software applications
and believes them to be generally Y2K compliant. Additional patches or software
upgrades will be applied no later than May 15, 1999 to complete this process.
The costs of all such risk assessments and remediation are not expected to be
material to the Programs.
5. Contingency Planning. Notwithstanding the foregoing, should there be
significant unanticipated disruptions in Samson's financial and administrative
systems, all of the accounting processes that are currently automated will need
to be performed manually. Samson will consider in the second half of 1999 its
options with respect to contingency arrangements for temporary staffing to
accommodate such situations.
Imbedded Systems
1. Awareness. Samson's Y2K program has involved all levels of field
personnel from production foremen and higher. Employees at all levels of the
organization have been asked to participate in the identification of potential
Y2K risks, which might otherwise go unnoticed by higher level employees and
officers of Samson, and as a result, awareness of the issue is considered high.
2. Risk Identification. Samson has inventoried all possible exposures to
imbedded chips and systems. Such exposures can be classified as either (i) oil
and gas production and processing equipment or (ii) office machines such as
faxes, copiers, phones, etc.
With respect to oil and gas production and processing equipment, neither
Samson nor the Programs operate offshore wells, significant processing plants,
or wells with older electronic monitoring systems. As a result, Samson's
inventory identified less than 10 applications using imbedded chips. All of
these are in the process of being tested by the respective vendors and are
expected to be Y2K compliant or replaced no later than May 30, 1999. Oil and gas
production related to such
-26-
<PAGE>
equipment is very minor with respect to the entire Samson group, and, in fact,
the Programs' production may not use such equipment at all.
Office machines are currently being tested by Samson and vendors. It is
expected that such machines will be made compliant or replaced no later than
May 15, 1999.
3. Risk Assessment and Remediation. The failure to identify and correct a
material Y2K problem in an imbedded system could result in outcomes ranging from
errors in data reporting to curtailments or shutdowns in production. As noted
above, Samson has identified less than 10 imbedded system applications that may
have a Y2K problem. None of these applications are believed to be material to
Samson or the Programs. Once identified, assessed and prioritized, Samson
intends to test and upgrade imbedded components and systems in field process
control units deemed to pose the greatest risk of significant non-compliance and
capable of testing. Samson believes that sufficient manual processes are
available to minimize any such field level risk and that there will be no
material impact on the Programs with respect to these applications.
4. Contingency Planning. Should material production disruptions occur as a
result of Y2K failures in field operations, Samson will utilize its existing
field personnel in an attempt to avoid any material impact on operating cash
flow. Samson is not able to quantify any potential exposure in the event of
systems failure or inadequate manual alternatives.
Third Party Exposures
1. Awareness. Samson has advised management to consider Y2K implications
with its outside vendors, customers, and business partners. Management has been
asked to participate in the identification of potential third party Y2K risks
and, as a result, awareness of the issue is considered high.
2. Risk Identification. Samson's most significant third party Y2K exposure
is its dependence on third parties for the receipt of revenues from oil and gas
sales. However, virtually all of these purchasers are very large and
sophisticated companies. Other Y2K concerns include the availability of electric
power to Samson's field operations, the integrity of telecommunication systems,
and the readiness of commercial banks to execute electronic fund transfers.
3. Risk Assessment. Because of the high awareness of the Y2K problem in
the U.S., Samson has not undertaken and does not plan to undertake a formal
company wide plan to make inquiries of third parties on the subject of Y2K
readiness. If it did so, Samson has no ability to require responses to such
inquiries or to independently verify their accuracy. Samson has, however,
-27-
<PAGE>
received oral assurances from its significant oil and gas purchasers of Y2K
compliance. If significant disruptions from major purchasers were to occur,
however, there could be a material and adverse impact on the Programs' results
of operations, liquidity, and financial conditions.
It is important to note that third party oil and gas purchasers have
significant incentives to avoid disruptions arising from a Y2K failure. For
example, most of these parties are under contractual obligations to purchase oil
and gas or disperse revenues to Samson. The failure to do so will result in
contractual and statutory penalties. Therefore, Dyco believes that it is
unlikely that there will be material third party non-compliance with purchase
and remittance obligations as a result of Y2K issues.
4. Remediation. Where Samson perceives significant risk of Y2K
non-compliance that may have a material impact on it, and where the relationship
between Samson and a vendor, customer, or business partner permits, joint
testing may be undertaken during 1999 to further identify these risks.
5. Contingency Planning. In the unlikely event that material production
disruptions occur as a result of Y2K failures of third parties, the Programs'
operating cash flow could be impacted. This contingency will be factored into
deliberations on the level of quarterly cash distributions paid out during any
such period of cash flow disruption.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK.
The Programs do not hold any market risk sensitive instruments.
-28-
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
DYCO OIL AND GAS PROGRAM 1979-1 LIMITED PARTNERSHIP
In our opinion, the accompanying balance sheets and the related statements
of operations, changes in partners' capital and cash flows present fairly, in
all material respects, the financial position of the Dyco Oil and Gas Program
1979-1 Limited Partnership, a Minnesota limited partnership, at December 31,
1998 and 1997, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Program's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these financial statements in accordance with generally accepted
auditing standards which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 12, 1999
-29-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-1 LIMITED PARTNERSHIP
Balance Sheets
December 31, 1998 and 1997
ASSETS
------
1998 1997
-------- --------
CURRENT ASSETS:
Cash and cash equivalents $ 54,891 $ 70,498
Accrued oil and gas sales 38,148 69,687
------- -------
Total current assets $ 93,039 $140,185
NET OIL AND GAS PROPERTIES, utilizing
the full cost method 123,292 179,341
DEFERRED CHARGE 31,576 48,506
------- -------
$247,907 $368,032
======= =======
LIABILITIES AND PARTNERS' CAPITAL
---------------------------------
CURRENT LIABILITIES:
Accounts payable $ 2,872 $ 2,778
Gas imbalance payable 5,084 105
------- -------
Total current liabilities $ 7,956 $ 2,883
ACCRUED LIABILITY $ 29,241 $ 37,026
PARTNERS' CAPITAL:
General Partner, 32 general
partner units $ 2,108 $ 3,282
Limited Partners, issued and
outstanding, 3,140 Units 208,602 324,841
------- -------
Total Partners' Capital $210,710 $328,123
------- -------
$247,907 $368,032
======= =======
The accompanying notes are an integral part of these
financial statements.
-30-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-1 LIMITED PARTNERSHIP
Statements of Operations
For the Years Ended December 31, 1998, 1997 and 1996
1998 1997 1996
-------- -------- --------
REVENUES:
Oil and gas sales $341,699 $468,867 $500,208
Interest 4,420 3,073 2,353
Gain on sale of oil
and gas properties 145,376 - -
------- ------- -------
$491,495 $471,940 $502,561
COSTS AND EXPENSES:
Lease operating $ 47,169 $ 55,138 $ 67,719
Production taxes 24,930 32,733 35,474
Depreciation, depletion, and
amortization of oil and
gas properties 24,232 39,290 33,690
General and administrative 52,637 55,701 54,220
------- ------- -------
$148,968 $182,862 $191,103
------- ------- -------
NET INCOME $342,527 $289,078 $311,458
======= ======= =======
GENERAL PARTNER (1%) -
NET INCOME $ 3,425 $ 2,891 $ 3,115
======= ======= =======
LIMITED PARTNERS (99%) -
NET INCOME $339,102 $286,187 $308,343
======= ======= =======
NET INCOME per Unit $ 107.98 $ 91.13 $ 98.19
======= ======= =======
UNITS OUTSTANDING 3,172 3,172 3,172
======= ======= =======
The accompanying notes are an integral part of these
financial statements.
-31-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-1 LIMITED PARTNERSHIP
Statements of Changes in Partners' Capital
For the Years Ended December 31, 1998, 1997, and 1996
General Limited
Partner Partners Total
-------- ---------- ----------
Balances at Dec. 31, 1995 $4,096 $405,471 $409,567
Cash distributions ( 3,172) ( 314,028) ( 317,200)
Net income 3,115 308,343 311,458
----- ------- -------
Balances at Dec. 31, 1996 $4,039 $399,786 $403,825
Cash distributions ( 3,648) ( 361,132) ( 364,780)
Net income 2,891 286,187 289,078
----- ------- -------
Balances at Dec. 31, 1997 $3,282 $324,841 $328,123
Cash distributions ( 4,599) ( 455,341) ( 459,940)
Net income 3,425 339,102 342,527
----- ------- -------
Balances at Dec. 31, 1998 $2,108 $208,602 $210,710
===== ======= =======
The accompanying notes are an integral part of these
financial statements.
-32-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-1 LIMITED PARTNERSHIP
Statements of Cash Flows
For the Years Ended December 31, 1998, 1997, and 1996
1998 1997 1996
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $342,527 $289,078 $311,458
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization of oil and gas
properties 24,232 39,290 33,690
Gain on sale of oil and
gas properties ( 145,376) - -
(Increase) decrease in accrued
oil and gas sales 31,539 32,294 ( 27,800)
Decrease in deferred charge 16,930 2,451 18,452
Increase (decrease) in accounts
payable 94 ( 1,564) ( 2,460)
Increase (decrease) in gas
imbalance payable 4,979 ( 11,538) ( 1,680)
Increase (decrease) in accrued
liability ( 7,785) 3,194 ( 4,292)
------- ------- -------
Net cash provided by operating
activities $267,140 $353,205 $327,368
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of oil and
gas properties $177,387 $ 22,624 $ 16,772
Additions to oil and gas properties ( 194) - -
------- ------- -------
Net cash provided by investing
activities $177,193 $ 22,624 $ 16,772
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions ($459,940) ($364,780) ($317,200)
------- ------- -------
Net cash used by financing activities ($459,940) ($364,780) ($317,200)
------- ------- -------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS ($ 15,607) $ 11,049 $ 26,940
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 70,498 59,449 32,509
------- ------- -------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 54,891 $ 70,498 $ 59,449
======= ======= =======
The accompanying notes are an integral
part of these financial statements.
-33-
<PAGE>
DYCO OIL AND GAS PROGRAM 1979-1 LIMITED PARTNERSHIP
Notes to Financial Statements
For the Years Ended December 31, 1998, 1997, and 1996
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
The Dyco Oil and Gas Program 1979-1 Limited Partnership (the
"Program"), a Minnesota limited partnership, commenced operations on April
2, 1979. Dyco Petroleum Corporation ("Dyco") is the General Partner of the
Program. Affiliates of Dyco owned 1,321 (42.1%) of the Program's Units at
December 31, 1998.
The Program's sole business is the development and production of oil
and gas with a concentration on gas. Substantially all of the Program's
gas reserves are being sold regionally in the "spot market." Due to the
highly competitive nature of the spot market, prices on the spot market
are subject to wide seasonal and regional pricing fluctuations. In
addition, such spot market sales are generally short-term in nature and
are dependent upon the obtaining of transportation services provided by
pipelines. The prices received for the Program's oil and gas are subject
to influences such as global consumption and supply trends.
Cash and Cash Equivalents
The Program considers all highly liquid investments with a maturity
of three months or less when purchased to be cash equivalents. Cash
equivalents are not insured, which cause the Program to be subject to
risk.
Credit Risk
Accrued oil and gas sales which are due from a variety of oil and
gas purchasers subject the Program to a concentration of credit risk. Some
of these purchasers are discussed in Note 3 - Major Customers.
Oil and Gas Properties
Oil and gas operations are accounted for using the full cost method
of accounting. All productive and non-productive costs associated with the
acquisition, exploration, and development of oil and gas reserves are
capitalized. Capitalized costs are depleted on the gross revenue method
using estimates of proved reserves. The full
-34-
<PAGE>
cost amortization rates per equivalent Mcf of gas produced during the
years ended December 31, 1998, 1997, and 1996 were $0.13, $0.19, and
$0.14, respectively. The Program's calculation of depreciation, depletion,
and amortization includes estimated future expenditures to be incurred in
developing proved reserves and estimated dismantlement and abandonment
costs, net of estimated salvage values. In the event the unamortized cost
of oil and gas properties being amortized exceeds the full cost ceiling
(as defined by the Securities and Exchange Commission("SEC")) the excess
is charged to expense in the year during which such excess occurs. Sales
and abandonments of properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and
proved oil and gas reserves. During the first quarter of 1998, the Program
sold several wells for $162,007 representing approximately 9% of its total
reserves. The proceeds from these sales would have reduced the net book
value of the oil and gas properties by 90%, significantly altering the
Program's capitalized cost/proved reserves relationship. Accordingly,
capitalized costs were reduced by approximately 9% with the remainder
recorded as a gain on sale of oil and gas properties.
Deferred Charge
The Deferred Charge at December 31, 1998 and 1997 represents costs
deferred for lease operating expenses incurred in connection with the
Program's underproduced gas imbalance positions. The rate used in
calculating the deferred charge is the average of the annual production
costs per Mcf. At December 31, 1998, cumulative total gas sales volumes
for underproduced wells were less than the Program's pro-rata share of
total gas production from these wells by 157,720 Mcf, resulting in prepaid
lease operating expenses of $31,576. At December 31, 1997, cumulative
total gas sales volumes for underproduced wells were less than the
Program's pro-rata share of total gas production from these wells by
195,983 Mcf, resulting in prepaid lease operating expenses of $48,506.
Accrued Liability
The Accrued Liability at December 31, 1998 and 1997 represents
charges accrued for lease operating expenses incurred in connection with
the Program's overproduced gas imbalance positions. The rate used in
calculating the accrued liability is the average of the annual production
costs per Mcf. At December 31, 1998, cumulative total gas sales volumes
for overproduced wells exceeded the Program's pro-rata share of total gas
production from these wells by
-35-
<PAGE>
146,057 Mcf, resulting in accrued lease operating expenses of $29,241. At
December 31, 1997, cumulative total gas sales volumes for overproduced
wells exceeded the Program's pro-rata share of total gas production from
these wells by 149,598 Mcf, resulting in accrued lease operating expenses
of $37,026.
Oil and Gas Sales and Gas Imbalance Payable
The Program's oil and condensate production is sold, title passed,
and revenue recognized at or near the Program's wells under short-term
purchase contracts at prevailing prices in accordance with arrangements
which are customary in the oil industry. Sales of gas applicable to the
Program's interest in producing oil and gas leases are recorded as income
when the gas is metered and title transferred pursuant to the gas sales
contracts covering the Program's interest in gas reserves. During such
times as the Program's sales of gas exceed its pro-rata ownership in a
well, such sales are recorded as income unless total sales from the well
have exceeded the Program's share of estimated total gas reserves
underlying the property at which time such excess is recorded as a
liability. The rates per Mcf used to calculate this liability are based on
the average gas prices received for the volumes at the time the
overproduction occurred. This also approximates the price for which the
Program is currently settling this liability. At December 31, 1998, total
sales exceeded the Program's share of estimated total gas reserves on two
wells by $5,084 (3,389 Mcf). At December 31, 1997, total sales exceeded
the Program's share of estimated total gas reserves on one well by $105
(70 Mcf).
Use of Estimates in Financial Statements
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. Further, the deferred charge, the gas imbalance payable, and
the accrued liability all involve estimates which could materially differ
from the actual amounts ultimately realized in the near term. Oil and gas
reserves (see Note 4) also involve significant estimates which could
materially differ from the actual amounts ultimately realized.
-36-
<PAGE>
Income Taxes
Income or loss for income tax purposes is includable in the income
tax returns of the partners. Accordingly, no recognition has been given to
income taxes in the accompanying financial statements.
2. TRANSACTIONS WITH RELATED PARTIES
Under the terms of the Program Agreement, Dyco is entitled to
receive a reimbursement for all direct expenses and general and
administrative, geological, and engineering expenses it incurs on behalf
of the Program. During the years ended December 31, 1998, 1997, and 1996,
such expenses totaled $52,637, $55,701, and $54,220, respectively, of
which $44,520 was paid each year to Dyco and its affiliates.
Affiliates of the Program operate certain of the Program's
properties. Their policy is to bill the Program for all customary charges
and cost reimbursements associated with these activities, together with
any compressor rentals, consulting, or other services provided. Such
charges are comparable to third party charges in the area where the wells
are located and are the same as charged to other working interest owners
in the wells.
3. MAJOR CUSTOMERS
The following purchasers individually accounted for 10% or more of
the combined oil and gas sales of the Program for the years ended December
31, 1998, 1997, and 1996:
Purchaser 1998 1997 1996
--------- ----- ----- ----
El Paso Energy
Marketing Company 79.1% 95.3% 94.8%
Enron Oil & Gas
Company 18.6% - % - %
In the event of interruption of purchases by these significant
customers or the cessation or material change in availability of
open-access transportation by the Program's pipeline transporters, the
Program may encounter difficulty in marketing its gas and in maintaining
historic sales levels. Alternative purchasers or transporters may not be
readily available.
-37-
<PAGE>
4. SUPPLEMENTAL OIL AND GAS INFORMATION
The following supplemental information regarding the oil and gas
activities of the Program is presented pursuant to the disclosure
requirements promulgated by the SEC.
Capitalized Costs
The Program's capitalized costs and accumulated depreciation,
depletion, amortization, and valuation allowance at December 31, 1998 and
1997 were as follows:
December 31,
-----------------------------
1998 1997
------------- ------------
Proved properties $20,381,071 $20,412,888
Less accumulated depreciation,
depletion, amortization, and
valuation allowance ( 20,257,779) ( 20,233,547)
---------- ----------
Net oil and gas properties $ 123,292 $ 179,341
========== ==========
Costs Incurred
The Program incurred no oil and gas property acquisition or
exploration costs during 1998, 1997, and 1996. Costs incurred by the
Program in connection with its oil and gas property development activities
during 1998, 1997, and 1996 were as follows:
December 31,
-------------------------
1998 1997 1996
---- ---- ----
Development costs $194 $ - $ -
=== === ====
-38-
<PAGE>
Quantities of Proved Oil and Gas Reserves - Unaudited
Set forth below is a summary of the changes in the net quantities of the
Program's proved crude oil and gas reserves for the years ended December 31,
1998, 1997, and 1996. Proved reserves were estimated by petroleum engineers
employed by affiliates of Dyco. All of the Program's reserves are located in the
United States. The following information includes certain gas balancing
adjustments which cause the gas volumes to differ from the reserve information
prepared by Dyco.
<TABLE>
<CAPTION>
1998 1997 1996
---------------------- ---------------------- -----------------------
Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
------- ---------- ------- ----------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves,
beginning of year 2,033 1,098,038 3,193 1,077,521 3,472 1,094,721
Revisions of previous
estimates 121 250,083 ( 736) 243,736 108 222,455
Sales of reserves ( 166) ( 117,612) ( 58) ( 18,130) ( 9) ( 1,266)
Production ( 291) ( 185,215) ( 366) ( 205,089) ( 378) ( 238,389)
----- --------- ----- --------- ----- ---------
Proved reserves,
end of year 1,697 1,045,294 2,033 1,098,038 3,193 1,077,521
===== ========= ===== ========= ===== =========
Proved developed reserves:
Beginning of year 2,033 1,098,038 3,193 1,077,521 3,472 1,094,721
----- --------- ----- --------- ----- ---------
End of year 1,697 1,045,294 2,033 1,098,038 3,193 1,077,521
===== ========= ===== ========= ===== =========
</TABLE>
-39-
<PAGE>
The process of estimating oil and gas reserves is complex, requiring
significant subjective decisions in the evaluation of available geological,
engineering, and economic data for each reservoir. The data for a given
reservoir may change substantially over time as a result of, among other things,
additional development activity, production history, and viability of production
under varying economic conditions; consequently, it is reasonably possible that
material revisions to existing reserve estimates may occur in the near future.
Although every reasonable effort has been made to ensure that the reserve
estimates reported herein represent the most accurate assessment possible, the
significance of the subjective decisions required and variances in available
data for various reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement disclosures.
The Program's reserves were determined at December 31, 1998 using oil and gas
prices of $9.50 per barrel and $2.03 per Mcf, respectively.
-40-
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
DYCO OIL AND GAS PROGRAM 1979-2 LIMITED PARTNERSHIP
In our opinion, the accompanying balance sheets and the related statements
of operations, changes in partners' capital and cash flows present fairly, in
all material respects, the financial position of the Dyco Oil and Gas Program
1979-2 Limited Partnership, a Minnesota limited partnership, at December 31,
1998 and 1997, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Program's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these financial statements in accordance with generally accepted
auditing standards which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 12, 1999
-41-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-2 LIMITED PARTNERSHIP
Balance Sheets
December 31, 1998 and 1997
ASSETS
------
1998 1997
-------- --------
CURRENT ASSETS:
Cash and cash equivalents $ 80,537 $157,539
Accrued oil and gas sales 48,948 81,158
------- -------
Total current assets $129,485 $238,697
NET OIL AND GAS PROPERTIES, utilizing
the full cost method 233,381 283,007
DEFERRED CHARGE 51,206 38,072
------- -------
$414,072 $559,776
======= =======
LIABILITIES AND PARTNERS' CAPITAL
---------------------------------
CURRENT LIABILITIES:
Accounts payable $ 5,817 $ 6,190
Payable to General Partner 11,439 -
Gas imbalance payable 58,811 53,853
------- -------
Total current liabilities $ 76,067 $ 60,043
ACCRUED LIABILITIES $ 28,873 $ 557
PARTNERS' CAPITAL:
General Partner, 29 general
partner units $ 3,092 $ 4,992
Limited Partners, issued and
outstanding, 2,860 Units 306,040 494,184
------- -------
Total Partners' Capital $309,132 $499,176
------- -------
$414,072 $559,776
======= =======
The accompanying notes are an integral part of these
financial statements.
-42-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-2 LIMITED PARTNERSHIP
Statements of Operations
For the Years Ended December 31, 1998, 1997 and 1996
1998 1997 1996
-------- -------- ----------
REVENUES:
Oil and gas sales $437,127 $695,928 $729,046
Interest and other income 7,903 9,287 6,280
------- ------- -------
$445,030 $705,215 $735,326
COSTS AND EXPENSES:
Lease operating $ 83,351 $ 75,640 $ 94,195
Production tax 30,549 51,876 53,147
Depreciation, depletion, and
amortization of oil and
gas properties 49,082 77,495 71,807
General and administrative 38,742 41,613 40,363
------- ------- -------
$201,724 $246,624 $259,512
------- ------- -------
NET INCOME $243,306 $458,591 $475,814
======= ======= =======
GENERAL PARTNER (1%) -
NET INCOME $ 2,433 $ 4,586 $ 4,758
======= ======= =======
LIMITED PARTNERS (99%) -
NET INCOME $240,873 $454,005 $471,056
======= ======= =======
NET INCOME per Unit $ 84.22 $ 158.74 $ 164.70
======= ======= =======
UNITS OUTSTANDING 2,889 2,889 2,889
======= ======= =======
The accompanying notes are an integral part of these
financial statements.
-43-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-2 LIMITED PARTNERSHIP
Statements of Changes in Partners' Capital
For the Years Ended December 31, 1998, 1997, and 1996
General Limited
Partner Partners Total
--------- ---------- ----------
Balances at Dec. 31, 1995 $6,626 $655,965 $662,591
Cash distributions ( 4,911) ( 486,219) ( 491,130)
Net income 4,758 471,056 475,814
----- ------- -------
Balances at Dec. 31, 1996 $6,473 $640,802 $647,275
Cash distributions ( 6,067) ( 600,623) ( 606,690)
Net income 4,586 454,005 458,591
----- ------- -------
Balances at Dec. 31, 1997 $4,992 $494,184 $499,176
Cash distributions ( 4,333) ( 429,017) ( 433,350)
Net income 2,433 240,873 243,306
----- ------- -------
Balances at Dec. 31, 1998 $3,092 $306,040 $309,132
===== ======= =======
The accompanying notes are an integral part of these
financial statements.
-44-
<PAGE>
DYCO OIL AND GAS PROGRAM
1979-2 LIMITED PARTNERSHIP
Statements of Cash Flows
For the Years Ended December 31, 1998, 1997, and 1996
1998 1997 1996
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $243,306 $458,591 $475,814
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization of oil and gas
properties 49,082 77,495 71,807
(Increase) decrease in accrued
oil and gas sales 32,210 87,713 ( 77,248)
(Increase) decrease in deferred
charge ( 13,134) 12,485 17,060
Increase (decrease) in
accounts payable ( 373) ( 4,924) 4,697
Increase in payable to
General Partner 11,439 - -
Increase in gas imbalance
payable 4,958 8,893 8,601
Increase (decrease) in
accrued liability 28,316 ( 5,756) 6,313
------- ------- -------
Net cash provided by operating
activities $355,804 $634,497 $507,044
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of oil
and gas properties $ 544 $ 6,213 $ 3,075
Additions to oil and gas properties - ( 84) ( 1,152)
------- ------- -------
Net cash provided by
investing activities $ 544 $ 6,129 $ 1,923
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions ($433,350) ($606,690) ($491,130)
------- ------- -------
Net cash used by financing
activities ($433,350) ($606,690) ($491,130)
------- ------- -------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS ($ 77,002) $ 33,936 $ 17,837
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 157,539 123,603 105,766
------- ------- -------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 80,537 $157,539 $123,603
======= ======= =======
The accompanying notes are an integral
part of these financial statements.
-45-
<PAGE>
DYCO OIL AND GAS PROGRAM 1979-2 LIMITED PARTNERSHIP
Notes to Financial Statements
For the Years Ended December 31, 1998, 1997, and 1996
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
The Dyco Oil and Gas Program 1979-2 Limited Partnership (the
"Program"), a Minnesota limited partnership, commenced operations on July
2, 1979. Dyco Petroleum Corporation ("Dyco") is the General Partner of the
Program. Affiliates of Dyco owned 1,223 (42.8%) of the Program's Units at
December 31, 1998.
The Program's sole business is the development and production of oil
and gas with a concentration on gas. Substantially all of the Program's
gas reserves are being sold regionally in the "spot market." Due to the
highly competitive nature of the spot market, prices on the spot market
are subject to wide seasonal and regional pricing fluctuations. In
addition, such spot market sales are generally short-term in nature and
are dependent upon the obtaining of transportation services provided by
pipelines.
Cash and Cash Equivalents
The Program considers all highly liquid investments with a maturity
of three months or less when purchased to be cash equivalents. Cash
equivalents are not insured, which cause the Program to be subject to
risk.
Credit Risk
Accrued oil and gas sales which are due from a variety of oil and gas
purchasers subject the Program to a concentration of credit risk. Some of
these purchasers are discussed in Note 3. Major Customers.
Oil and Gas Properties
Oil and gas operations are accounted for using the full cost method
of accounting. All productive and non-productive costs associated with the
acquisition, exploration, and development of oil and gas reserves are
capitalized. Capitalized costs are depleted on the gross revenue method
using estimates of proved reserves. The full cost amortization rates per
equivalent Mcf of gas produced during the years ended December 31, 1998,
1997, and 1996 were $0.25, $0.28, and $0.24, respectively. The Program's
calculation of depreciation, depletion, and amortization
-46-
<PAGE>
includes estimated future expenditures to be incurred in developing proved
reserves and estimated dismantlement and abandonment costs, net of
estimated salvage values. In the event the unamortized cost of oil and gas
properties being amortized exceeds the full cost ceiling (as defined by
the Securities and Exchange Commission ("SEC")) the excess is charged to
expense in the year during which such excess occurs. Sales and
abandonments of properties are accounted for as adjustments of capitalized
costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
oil and gas reserves.
Deferred Charge
The Deferred Charge at December 31, 1998 and 1997 represents costs
deferred for lease operating expenses incurred in connection with the
Program's underproduced gas imbalance positions. The rate used in
calculating the deferred charge is the average of the annual production
costs per Mcf. At December 31, 1998, cumulative total gas sales volumes
for underproduced wells were less than the Program's pro-rata share of
total gas production from these wells by 144,813 Mcf, resulting in prepaid
lease operating expenses of $51,206. At December 31, 1997, cumulative
total gas sales volumes for underproduced wells were less than the
Program's pro-rata share of total gas production from these wells by
151,078 Mcf, resulting in prepaid lease operating expenses of $38,072.
Payable to General Partner
The payable to General Partner at December 31, 1998 represents an
overpayment of gas sales in 1998.
Accrued Liability
The Accrued Liability at December 31, 1998 and 1997 represents
charges accrued for lease operating expenses incurred in connection with
the Program's overproduced gas imbalance positions. The rate used in
calculating the accrued liability is the average of the annual production
costs per Mcf. At December 31, 1998, cumulative total gas sales volumes
for overproduced wells exceeded the Program's pro-rata share of total gas
production from these wells by 81,654 Mcf, resulting in accrued lease
operating expenses of $28,873. At December 31, 1997, cumulative total gas
sales volumes for overproduced wells exceeded the Program's pro-rata share
of total gas production from these wells by 2,211 Mcf, resulting in
accrued lease operating expenses of $557.
-47-
<PAGE>
Oil and Gas Sales and Gas Imbalance Payable
The Program's oil and condensate production is sold, title passed,
and revenue recognized at or near the Program's wells under short-term
purchase contracts at prevailing prices in accordance with arrangements
which are customary in the oil industry. Sales of gas applicable to the
Program's interest in producing oil and gas leases are recorded as income
when the gas is metered and title transferred pursuant to the gas sales
contracts covering the Program's interest in gas reserves. During such
times as the Program's sales of gas exceed its pro-rata ownership in a
well, such sales are recorded as income unless total sales from the well
have exceeded the Program's share of estimated total gas reserves
underlying the property at which time such excess is recorded as a
liability. The rates per Mcf used to calculate this liability are based on
the average gas prices received for the volumes at the time the
overproduction occurred. At December 31, 1998, total sales exceeded the
Program's share of estimated total gas reserves on one well by $58,811
(39,207 Mcf). At December 31, 1997, total sales exceeded the Program's
share of estimated total gas reserves on one well by $53,853 (35,902 Mcf).
Use of Estimates in Financial Statements
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. Further, the deferred charge, the gas imbalance payable, and
accrued liability all involve estimates which could materially differ from
the actual amounts ultimately realized in the near term. Oil and gas
reserves (see Note 4) also involve significant estimates which could
materially differ from the actual amounts ultimately realized.
Income Taxes
Income or loss for income tax purposes is includable in the income
tax returns of the partners. Accordingly, no recognition has been given to
income taxes in the accompanying financial statements.
-48-
<PAGE>
2. TRANSACTIONS WITH RELATED PARTIES
Under the terms of the Program Agreement, Dyco is entitled to
receive a reimbursement for all direct expenses and general and
administrative, geological, and engineering expenses it incurs on behalf
of the Program. During the years ended December 31, 1998, 1997, and 1996,
such expenses totaled $38,742, $41,613, and $40,363, respectively, of
which $31,212 was paid each year to Dyco and its affiliates.
Affiliates of the Program operate certain of the Program's
properties. Their policy is to bill the Program for all customary charges
and cost reimbursements associated with these activities, together with
any compressor rentals, consulting, or other services provided. Such
charges are comparable to third party charges in the area where the wells
are located and are the same as charged to other working interest owners
in the wells.
3. MAJOR CUSTOMERS
The following purchasers individually accounted for 10% or more of
the combined oil and gas sales for the years ended December 31, 1998,
1997, and 1996:
Purchaser 1998 1997 1996
--------- ----- ----- -----
El Paso Energy
Marketing Company 74.6% 60.0% 74.8%
Williams Energy
Services Company - % 22.9% - %
In the event of interruption of purchases by these significant
customers or the cessation or material change in availability of
open-access transportation by the Program's pipeline transporters, the
Program may encounter difficulty in marketing its gas and in maintaining
historic sales levels. Alternative purchasers or transporters may not be
readily available.
4. SUPPLEMENTAL OIL AND GAS INFORMATION
The following supplemental information regarding the oil and gas
activities of the Program is presented pursuant to the disclosure
requirements promulgated by the SEC.
-49-
<PAGE>
Capitalized Costs
The Program's capitalized costs and accumulated depreciation,
depletion, amortization, and valuation allowance at December 31, 1998 and
1997 were as follows:
December 31,
-------------------------------
1998 1997
------------- -------------
Proved properties $18,553,948 $18,554,492
Less accumulated depreciation,
depletion, amortization, and
valuation allowance ( 18,320,567) ( 18,271,485)
---------- ----------
Net oil and gas properties $ 233,381 $ 283,007
========== ==========
Costs Incurred
The Program incurred no oil and gas property acquisition or
exploration costs during 1998, 1997, and 1996. Costs incurred by the
Program in connection with its oil and gas property development activities
during 1998, 1997, and 1996 were as follows:
December 31,
---------------------------
1998 1997 1996
---- ------ ------
Development costs $ - $ 84 $1,152
=== === =====
-50-
<PAGE>
Quantities of Proved Oil and Gas Reserves - Unaudited
Set forth below is a summary of the changes in the net quantities of the
Program's proved crude oil and gas reserves for the years ended December 31,
1998, 1997, and 1996. Proved reserves were estimated by petroleum engineers
employed by affiliates of the Program. All of the Program's reserves are located
in the United States. The following information includes certain gas balancing
adjustments which cause the gas volumes to differ from the reserve information
prepared by Dyco.
<TABLE>
<CAPTION>
1998 1997 1996
----------------------- ----------------------- ---------------------
Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
-------- ----------- ------- ----------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves,
beginning of year 12,515 1,070,721 12,678 955,767 13,652 1,137,576
Revisions of previous
estimates 423 143,663 1,202 388,548 422 122,479
Sales of reserves - - ( 40) ( 8,185) ( 60) ( 8,044)
Production ( 1,067) ( 191,087) ( 1,325) ( 265,409) ( 1,336) ( 296,244)
------ --------- ------ --------- ----- ---------
Proved reserves,
end of year 11,871 1,023,297 12,515 1,070,721 12,678 955,767
====== ========= ====== ========= ====== =========
Proved developed
reserves:
Beginning of year 12,515 1,070,721 12,678 955,767 13,652 1,137,576
------ --------- ------ --------- ------ ---------
End of year 11,871 1,023,297 12,515 1,070,721 12,678 955,767
====== ========= ====== ========= ====== =========
</TABLE>
-51-
<PAGE>
The process of estimating oil and gas reserves is complex, requiring
significant subjective decisions in the evaluation of available
geological, engineering, and economic data for each reservoir. The data
for a given reservoir may change substantially over time as a result of,
among other things, additional development activity, production history,
and viability of production under varying economic conditions;
consequently, it is reasonably possible that material revisions to
existing reserve estimates may occur in the near future. Although every
reasonable effort has been made to ensure that the reserve estimates
reported herein represent the most accurate assessment possible, the
significance of the subjective decisions required and variances in
available data for various reservoirs make these estimates generally less
precise than other estimates presented in connection with financial
statement disclosures. The Program's reserves were determined at December
31, 1998 using oil and gas prices of $9.50 per barrel and $2.03 per Mcf,
respectively.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Programs are limited partnerships and have no directors or executive
officers. The following individuals are directors and executive officers of
Dyco, the General Partner. The business address of such directors and executive
officers is Two West Second Street, Tulsa, Oklahoma 74103.
NAME AGE POSITION WITH GENERAL PARTNERS
---------------- --- --------------------------------
Dennis R. Neill 47 President and Director
Patrick M. Hall 40 Chief Financial Officer
Judy K. Fox 48 Secretary
The director will hold office until the next annual meeting of
shareholders of Dyco and until his successor has been duly elected and
qualified. All executive officers serve at the discretion of the Board of
Directors.
Dennis R. Neill joined Samson in 1981, was named Senior Vice President and
Director of Dyco on June 18, 1991, and was named President of Dyco on June 30,
1996. Prior to joining Samson, he was associated with a Tulsa law firm, Conner
and Winters, where
-52-
<PAGE>
his principal practice was in the securities area. He received a Bachelor of
Arts degree in political science from Oklahoma State University and a Juris
Doctorate degree from the University of Texas. Mr. Neill also serves as Senior
Vice President of Samson Investment Company and as President and Director of
Samson Properties Incorporated, Samson Hydrocarbons Company, Berry Gas Company,
Circle L Drilling Company, Compression, Inc., and Geodyne Resources, Inc. and
its subsidiaries.
Patrick M. Hall joined Samson in 1983, was named a Vice President of Dyco
on June 18, 1991, and was named Chief Financial Officer of Dyco on June 30,
1996. Prior to joining Samson he was a senior accountant with Peat Marwick Main
& Co. in Tulsa. He holds a Bachelor of Science degree in accounting from
Oklahoma State University and is a Certified Public Accountant. Mr. Hall also
serves as Senior Vice President - Controller of Samson Investment Company.
Judy K. Fox joined Samson in 1990 and was named Secretary of Dyco on June
30, 1996. Prior to joining Samson, she served as Gas Contract Manager for Ely
Energy Company. Ms. Fox is also Secretary of Berry Gas Company, Circle L
Drilling Company, Compression, Inc., Samson Hydrocarbons Company, Samson
Properties Incorporated, and Geodyne Resources, Inc.
and its subsidiaries.
Section 16(a) Beneficial Ownership Reporting Compliance
To the best knowledge of the Programs and Dyco, there were no officers,
directors, or ten percent owners who were delinquent filers during 1998 of
reports required under Section 16(a) of the Securities and Exchange Act of 1934.
ITEM 11. EXECUTIVE COMPENSATION
The Programs are limited partnerships and, therefore, have no officers or
directors. The following table summarizes the amounts paid by the Programs as
compensation and reimbursements to Dyco and its affiliates for the three years
ended December 31, 1998:
-53-
<PAGE>
Compensation/Reimbursement to Dyco and its affiliates
Three Years Ended December 31, 1998
Type of Compensation/Reimbursement(1) Expense
- ------------------------------------- -----------------------------
1998 1997 1996
------- ------- -------
1979-1 Program
- --------------
Compensation:
Operations (2) (2) (2)
Reimbursements:
General and Administrative,
Geological, and Engineering
Expenses and Direct Expenses(3) $44,520 $44,520 $44,520
1979-2 Program
- --------------
Compensation:
Operations (2) (2) (2)
Reimbursements:
General and Administrative,
Geological, and Engineering
Expenses and Direct Expenses(3) $31,212 $31,212 $31,212
- ---------------
(1) The authority for all of such compensation and reimbursement is the
Program Agreements. With respect to the Operations activities noted in the
table, management believes that such compensation is equal to or less than
that charged by unaffiliated persons in the same geographic areas and
under the same conditions.
(2) Affiliates of the Programs serve as operator of some of the Programs'
wells. Dyco, as General Partner, contracts with such affiliates for
services as operator of the wells. As operator, such affiliates are
compensated at rates provided in the operating agreements in effect and
charged to all parties to such agreement. The dollar amount of such
compensation paid by the Programs to such affiliates is impossible to
quantify as of the date of this Annual Report.
(3) The Programs reimburse Dyco and its affiliates for reasonable and
necessary general and administrative, geological, and engineering expenses
and direct expenses incurred in connection with their management and
operation of the Programs. The directors, officers, and employees of Dyco
and its affiliates receive no direct remuneration from the Programs for
their services to the Programs. See "Salary Reimbursement Table" below.
The allocable general
-54-
<PAGE>
and administrative, geological, and engineering expenses are apportioned
on a reasonable basis between the Programs' business and all other oil and
gas activities of Dyco and its affiliates, including Dyco's management and
operation of affiliated oil and gas limited partnerships. The allocation
to the Programs of these costs is made by Dyco as General Partner.
As noted in the Compensation/Reimbursement Table above, the directors,
officers, and employees of Dyco and their affiliates receive no direct
remuneration from the Programs for their services. However, to the extent such
services represent direct involvement with the Programs, as opposed to general
corporate functions, such persons' salaries are allocated to and reimbursed by
the Programs. Such allocation to the Programs' general and administrative,
geological, and engineering expenses of the salaries of directors, officers, and
employees of Dyco and its affiliates is based on internal records maintained by
Dyco and its affiliates, and represents investor relations, legal, accounting,
data processing, management, gas marketing, and other functions directly
attributable to the Programs' operations. The following table indicates the
approximate amount of general and administrative expense reimbursement
attributable to the salaries of the directors, officers, and employees of Dyco
and its affiliates for the three years ended December 31, 1998:
-55-
<PAGE>
<TABLE>
<CAPTION>
1979-1 Program
--------------
Salary Reimbursement
Three Years Ended December 31, 1998
Long Term Compensation
------------------------------
Annual Compensation Awards Payouts
--------------------------------- --------------------- -------
Securi-
Other ties All
Name Annual Restricted Under- Other
and Compen- Stock lying LTIP Compen-
Principal Salary Bonus sation Award(s) Options/ Payouts sation
Position Year ($) ($) ($) ($) SARs(#) ($) ($)
- --------------- ---- ------- ------- ------- ---------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
C. Philip
Tholen,
President,
Chief Executive
Officer(1)(2) 1996 - - - - - - -
Dennis R. Neill,
President(2)(3) 1996 - - - - - - -
1997 - - - - - - -
1998 - - - - - - -
All Executive
Officers,
Directors,
and Employees
as a group(4) 1996 $26,044 - - - - - -
1997 $26,596 - - - - - -
1998 $26,347 - - - - - -
- ---------------
(1) Mr. Tholen served as President and Chief Executive Officer of Dyco until
June 30, 1996.
(2) The general and administrative expenses paid by the Program and attributable to
salary reimbursements do not include any salary or other compensation attributable to
Mr. Tholen or Mr. Neill.
(3) Mr. Neill became President of Dyco on June 30, 1996.
(4) No officer or director of Dyco or its affiliates provides full-time
services to the Program and no individual's salary or other compensation
reimbursement from the Program equals or exceeds $100,000 per annum.
</TABLE>
-56-
<PAGE>
<TABLE>
<CAPTION>
1979-2 Program
--------------
Salary Reimbursement
Three Years Ended December 31, 1998
Long Term Compensation
------------------------------
Annual Compensation Awards Payouts
--------------------------------- --------------------- -------
Securi-
Other ties All
Name Annual Restricted Under- Other
and Compen- Stock lying LTIP Compen-
Principal Salary Bonus sation Award(s) Options/ Payouts sation
Position Year ($) ($) ($) ($) SARs(#) ($) ($)
- --------------- ---- ------- ------- ------- ---------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
C. Philip
Tholen,
President,
Chief Executive
Officer(1)(2) 1996 - - - - - - -
Dennis R. Neill,
President(2)(3) 1996 - - - - - - -
1997 - - - - - - -
1998 - - - - - - -
All Executive
Officers,
Directors,
and Employees
as a group(4) 1996 $18,259 - - - - - -
1997 $18,646 - - - - - -
1998 $18,471 - - - - - -
- ---------------
(1) Mr. Tholen served as President and Chief Executive Officer of Dyco until
June 30, 1996.
(2) The general and administrative expenses paid by the Program and attributable to
salary reimbursements do not include any salary or other compensation attributable to
Mr. Tholen or Mr. Neill.
(3) Mr. Neill became President of Dyco on June 30, 1996.
(4) No officer or director of Dyco or its affiliates provides full-time
services to the Program and no individual's salary or other compensation
reimbursement from the Program equals or exceeds $100,000 per annum.
</TABLE>
-57-
<PAGE>
Samson maintains necessary inventories of new and used field equipment.
Samson may have provided some of this equipment for wells in which the Programs
have an interest. This equipment was provided at prices or rates equal to or
less than those normally charged in the same or comparable geographic area by
unaffiliated persons or companies dealing at arm's length. The operators of
these wells bill the Programs for a portion of such costs based upon the
Programs' interest in the well.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table provides information as to the beneficial ownership of
the Programs' Units as of March 1, 1999 by each beneficial owner of more than 5%
of the issued and outstanding Units and by the directors, officers, and
affiliates of Dyco. The address of each of such persons is Samson Plaza, Two
West Second Street, Tulsa, Oklahoma 74103.
Number of
Units
Beneficially
Owned (Percent
Beneficial Owner of Outstanding)
- ---------------------------------------------- ---------------
1979-1 Program:
- --------------
Samson Resources Company 1,321 (42.1%)
All directors, officers, and affiliates
of Dyco as a group and Dyco (5 persons) 1,321 (42.1%)
1979-2 Program:
- --------------
Samson Resources Company 1,224 (42.8%)
All directors, officers, and affiliates
of Dyco as a group and Dyco (5 persons) 1,224 (42.8%)
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Certain affiliates of Dyco engage in oil and gas activities independently
of the Programs which result in conflicts of interest that cannot be totally
eliminated. The allocation of acquisition and drilling opportunities and the
nature of the compensation arrangements between the Programs and such affiliates
also create potential conflicts of interest. An affiliate of the Program owns a
significant amount of the
-58-
<PAGE>
Programs' Units and therefore has an identity of interest with other limited
partners with respect to the operations of the Programs.
In order to attempt to assure limited liability for limited partners as
well as an orderly conduct of business, management of the Programs is exercised
solely by Dyco. The Program Agreements grant Dyco broad discretionary authority
with respect to the Programs' participation in drilling prospects and
expenditure and control of funds, including borrowings. These provisions are
similar to those contained in prospectuses and partnership agreements for other
public oil and gas partnerships. Broad discretion as to general management of
the Programs involves circumstances where Dyco has conflicts of interest and
where it must allocate costs and expenses, or opportunities, among the Programs
and other competing interests.
Dyco does not devote all of its time, efforts, and personnel exclusively
to the Programs. Furthermore, the Programs do not have any employees, but
instead rely on the personnel of Samson. The Programs thus compete with Samson
(including other oil and gas programs) for the time and resources of such
personnel. Samson devotes such time and personnel to the management of the
Programs as are indicated by the circumstances and as are consistent with Dyco's
fiduciary duties.
Affiliates of the Programs are solely responsible for the negotiation,
administration, and enforcement of oil and gas sales agreements covering the
Programs' leasehold interests. Because affiliates of the Programs who provide
services to the Programs have fiduciary or other duties to other members of
Samson, contract amendments and negotiating positions taken by them in their
effort to enforce contracts with purchasers may not necessarily represent the
positions that a Program would take if it were to administer its own contracts
without involvement with other members of Samson. On the other hand, management
believes that the Programs' negotiating strength and contractual positions have
been enhanced by virtue of its affiliation with Samson.
Samson Resources Company, an affiliate of Dyco, ("Resources") owns
approximately 42% and 43% of the 1979-1 and 1979-2 Programs' outstanding Units
as of March 1, 1999. The Program Agreements permit Resources to independently
vote its Units. Resources' significant Unit ownership will therefore likely
determine the outcome of any matter submitted for a vote of the Limited
Partners.
-59-
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements, Financial Statement Schedules, and Exhibits.
(1) Financial Statements: The following financial statements for
the Programs as of December 31, 1998 and 1997 and for the
years ended December 31, 1998, 1997, and 1996 are filed as
part of this report:
Reports of Independent Accountants
Balance Sheets
Statements of Operations
Statements of Changes in Partners' Capital
Statements of Cash Flows
Notes to Financial Statements
(2) Financial Statement Schedules:
None.
(3) Exhibits:
4.1 Drilling Agreement dated April 2, 1979 for Dyco Drilling
Program 1979-1 by and between Dyco Oil and Gas Program
1979-1, Dyco Petroleum Corporation, and Jaye F. Dyer
filed as Exhibit 4.1 to Annual Report on Form 10-K for
the year ended December 31, 1991 on April 10, 1992 and
is hereby incorporated herein.
4.2 Form of Program Agreement for Dyco Oil and Gas Program
1979-1 by and between Dyco Petroleum Corporation and the
Participants filed as Exhibit 4.2 to Annual Report on
Form 10-K for the year ended December 31, 1991 on April
10, 1992 and is hereby incorporated herein.
4.3 Amendment to Program Agreement for Dyco Oil and Gas
Program 1979-1 dated February 9, 1989 filed as Exhibit
4.3 to Annual Report on Form 10-K for the year ended
December 31, 1991 on April 10, 1992 and is hereby
incorporated herein.
4.4 Certificate of Limited Partnership (as amended) for Dyco
Oil and Gas Program 1979-1 Limited Partnership filed as
Exhibit 4.4 to Annual Report on Form 10-K for the year
ended
-60-
<PAGE>
December 31, 1991 on April 10, 1992 and is hereby
incorporated herein.
4.5 Drilling Agreement dated July 2, 1979 for Dyco Drilling
Program 1979-2 by and between Dyco Oil and Gas Program
1979-2, Dyco Petroleum Corporation, and Jaye F. Dyer
filed as Exhibit 4.5 to Annual Report on Form 10-K for
the year ended December 31, 1991 on April 10, 1992 and
is hereby incorporated herein.
4.6 Form of Program Agreement for Dyco Oil and Gas Program
1979-2 by and between Dyco Petroleum Corporation and the
Participants filed as Exhibit 4.6 to Annual Report on
Form 10-K for the year ended December 31, 1991 on April
10, 1992 and is hereby incorporated herein.
4.7 Amendment to Program Agreement for Dyco Oil and Gas
Program 1979-2 dated February 9, 1989 filed as Exhibit
4.7 to Annual Report on Form 10-K for the year ended
December 31, 1991 on April 10, 1992 and is hereby
incorporated herein.
4.8 Certificate of Limited Partnership (as amended) for Dyco
Oil and Gas Program 1979-2 Limited Partnership filed as
Exhibit 4.8 to Annual Report on Form 10-K for the year
ended December 31, 1991 on April 10, 1992 and is hereby
incorporated herein.
*27.1 Financial Data Schedule containing summary financial
information extracted from the Dyco Oil and Gas Program
1979-1 Limited Partnership's financial statements as of
December 31, 1998 and for the year ended December 31,
1998.
*27.2 Financial Data Schedule containing summary financial
information extracted from the Dyco Oil and Gas Program
1979-2 Limited Partnership's financial statements as of
December 31, 1998 and for the year ended December 31,
1998.
All other Exhibits are omitted as inapplicable.
------------------
* Filed herewith.
-61-
<PAGE>
(b) Reports on Form 8-K filed during the fourth quarter of 1998:
None.
-62-
<PAGE>
SIGNATURES
Pursuant to the requirements of Sections 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 organized.
DYCO OIL AND GAS PROGRAM 1979-1
LIMITED PARTNERSHIP
By: DYCO PETROLEUM CORPORATION
General Partner
March 25, 1999
By: /s/Dennis R. Neill
------------------------------
Dennis R. Neill
President
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 on the dates indicated.
By: /s/Dennis R. Neill President and March 25, 1999
------------------- Director (Principal
Dennis R. Neill Executive Officer)
/s/Patrick M. Hall Chief Financial March 25, 1999
------------------- Officer (Principal
Patrick M. Hall Financial and
Accounting Officer)
/s/Judy K. Fox Secretary March 25, 1999
-------------------
Judy K. Fox
-63-
<PAGE>
SIGNATURES
Pursuant to the requirements of Sections 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 organized.
DYCO OIL AND GAS PROGRAM 1979-2
LIMITED PARTNERSHIP
By: DYCO PETROLEUM CORPORATION
General Partner
March 25, 1999
By: /s/Dennis R. Neill
------------------------------
Dennis R. Neill
President
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 on the dates indicated.
By: /s/Dennis R. Neill President and March 25, 1999
------------------- Director (Principal
Dennis R. Neill Executive Officer)
/s/Patrick M. Hall Chief Financial March 25, 1999
------------------- Officer (Principal
Patrick M. Hall Financial and
Accounting Officer)
/s/Judy K. Fox Secretary March 25, 1999
-------------------
Judy K. Fox
-64-
<PAGE>
INDEX TO EXHIBITS
Exhibit
Number Description
- ------- -----------
4.1 Drilling Agreement dated April 2, 1979 for Dyco Drilling Program
1979-1 by and between Dyco Oil and Gas Program 1979-1, Dyco
Petroleum Corporation, and Jaye F. Dyer filed as Exhibit 4.1 to
Annual Report on Form 10-K for the year ended December 31, 1991 on
April 10, 1992 and is hereby incorporated herein.
4.2 Form of Program Agreement for Dyco Oil and Gas Program 1979-1 by and
between Dyco Petroleum Corporation and the Participants filed as
Exhibit 4.2 to Annual Report on Form 10-K for the year ended
December 31, 1991 on April 10, 1992 and is hereby incorporated
herein.
4.3 Amendment to Program Agreement for Dyco Oil and Gas Program 1979-1
dated February 9, 1989 filed as Exhibit 4.3 to Annual Report on Form
10-K for the year ended December 31, 1991 on April 10, 1992 and is
hereby incorporated herein.
4.4 Certificate of Limited Partnership (as amended) for Dyco Oil and Gas
Program 1979-1 Limited Partnership filed as Exhibit 4.4 to Annual
Report on Form 10-K for the year ended December 31, 1991 on April
10, 1992 and is hereby incorporated herein.
4.5 Drilling Agreement dated July 2, 1979 for Dyco Drilling Program
1979-2 by and between Dyco Oil and Gas Program 1979-2, Dyco
Petroleum Corporation, and Jaye F. Dyer filed as Exhibit 4.5 to
Annual Report on Form 10-K for the year ended December 31, 1991 on
April 10, 1992 and is hereby incorporated herein.
4.6 Form of Program Agreement for Dyco Oil and Gas Program 1979-2 by and
between Dyco Petroleum Corporation and the Participants filed as
Exhibit 4.6 to Annual Report on Form 10-K for the year ended
December 31, 1991 on April 10, 1992 and is hereby incorporated
herein.
4.7 Amendment to Program Agreement for Dyco Oil and Gas Program 1979-2
dated February 9, 1989 filed as Exhibit 4.7 to Annual Report on Form
10-K for the year ended December 31, 1991 on April 10, 1992 and is
hereby incorporated herein.
4.8 Certificate of Limited Partnership (as amended) for Dyco Oil and Gas
Program 1979-2 Limited Partnership filed as Exhibit 4.8 to Annual
Report on Form 10-K for
-65-
<PAGE>
the year ended December 31, 1991 on April 10, 1992 and is hereby
incorporated herein.
*27.1 Financial Data Schedule containing summary financial information
extracted from the Dyco Oil and Gas Program 1979-1 Limited
Partnership's financial statements as of December 31, 1998 and for
the year ended December 31, 1998.
*27.2 Financial Data Schedule containing summary financial information
extracted from the Dyco Oil and Gas Program 1979-2 Limited
Partnership's financial statements as of December 31, 1998 and for
the year ended December 31, 1998.
- ------------------
* Filed herewith.
-66-
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000806573
<NAME> DYCO OIL & GAS PROGRAM 1979-1 LTD PSHIP
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 54,891
<SECURITIES> 0
<RECEIVABLES> 38,148
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 93,039
<PP&E> 20,381,071
<DEPRECIATION> 20,257,779
<TOTAL-ASSETS> 247,907
<CURRENT-LIABILITIES> 7,956
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 210,710
<TOTAL-LIABILITY-AND-EQUITY> 247,907
<SALES> 341,699
<TOTAL-REVENUES> 491,495
<CGS> 0
<TOTAL-COSTS> 148,968
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 342,527
<INCOME-TAX> 0
<INCOME-CONTINUING> 342,527
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 342,527
<EPS-PRIMARY> 107.98
<EPS-DILUTED> 0
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000806574
<NAME> DYCO OIL & GAS PROGRAM 1979-2 LTD PSHIP
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 80,537
<SECURITIES> 0
<RECEIVABLES> 48,948
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 129,485
<PP&E> 18,553,948
<DEPRECIATION> 18,320,567
<TOTAL-ASSETS> 414,072
<CURRENT-LIABILITIES> 76,067
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 309,132
<TOTAL-LIABILITY-AND-EQUITY> 414,072
<SALES> 437,127
<TOTAL-REVENUES> 445,030
<CGS> 0
<TOTAL-COSTS> 201,724
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 243,306
<INCOME-TAX> 0
<INCOME-CONTINUING> 243,306
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 243,306
<EPS-PRIMARY> 84.22
<EPS-DILUTED> 0
</TABLE>
