FORM 10-K
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, 2004
Commission File Number:
III-A: 0-18302; III-B: 0-18636; III-C: 0-18634; III-D: 0-18936
III-E: 0-19010; III-F: 0-19102
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-A
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-B
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-C
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-D
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-E
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-F
-----------------------------------------------
(Exact name of Registrant as specified in its Articles)
III-A: 73-1352993
III-B: 73-1358666
III-C: 73-1356542
III-D: 73-1357374
III-E: 73-1367188
Oklahoma III-F: 73-1377737
- --------------------------------- ----------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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:
Depositary 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
----- -----
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
X Disclosure is not contained herein.
-----
Disclosure is contained herein.
-----
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes No X
----- -----
The Depositary Units 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
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FORM 10-K
TABLE OF CONTENTS
PART I.......................................................................4
ITEM 1. BUSINESS...................................................4
ITEM 2. PROPERTIES.................................................9
ITEM 3. LEGAL PROCEEDINGS.........................................25
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF LIMITED PARTNERS.......26
PART II.....................................................................26
ITEM 5. MARKET FOR UNITS AND RELATED LIMITED PARTNER MATTERS......26
ITEM 6. SELECTED FINANCIAL DATA...................................28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.......................35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...............59
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.......................59
ITEM 9A. CONTROLS AND PROCEDURES...................................59
ITEM 9B. OTHER INFORMATION.........................................59
PART III....................................................................59
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER...59
ITEM 11. EXECUTIVE COMPENSATION....................................61
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT................................................68
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............69
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES....................71
PART IV.....................................................................72
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES................72
SIGNATURES............................................................83
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PART I
ITEM 1. BUSINESS
General
The Geodyne Energy Income Limited Partnership III-A (the "III-A
Partnership"), Geodyne Energy Income Limited Partnership III-B (the "III-B
Partnership"), Geodyne Energy Income Limited Partnership III-C (the "III-C
Partnership"), Geodyne Energy Income Limited Partnership III-D (the "III-D
Partnership"), Geodyne Energy Income Limited Partnership III-E (the "III-E
Partnership"), and Geodyne Energy Income Limited Partnership III-F (the "III-F
Partnership") (collectively, the "Partnerships") are limited partnerships formed
under the Oklahoma Revised Uniform Limited Partnership Act. Each Partnership is
composed of Geodyne Resources, Inc., a Delaware corporation, as general partner
("Geodyne" or the "General Partner"), Geodyne Depositary Company, a Delaware
corporation, as the sole initial limited partner, and public investors as
substitute limited partners (the "Limited Partners"). The Partnerships commenced
operations on the dates set forth below:
Date of
Partnership Activation
----------- ------------------
III-A November 22, 1989
III-B January 24, 1990
III-C February 27, 1990
III-D September 5, 1990
III-E December 26, 1990
III-F March 7, 1991
The General Partner currently serves as general partner of 26 limited
partnerships and is a wholly-owned subsidiary of Samson Investment Company.
Samson Investment Company and its various corporate subsidiaries, including the
General Partner (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 December 31, 2004, Samson owned
interests in approximately 16,000 oil and gas wells located in 18 states of the
United States and the countries of Canada, Venezuela, and Australia. At December
31, 2004, Samson operated approximately 5,000 oil and gas wells located in 14
states of the United States as well as Canada, Venezuela, and Australia.
The Partnerships are currently engaged in the business of owning interests
in producing oil and gas properties located in the continental United States.
The Partnerships may also engage to a limited extent in development drilling on
producing oil and gas properties as required for the prudent management of the
Partnerships.
-4-
As limited partnerships, the Partnerships have no officers, directors, or
employees. They rely instead on the personnel of the General Partner and Samson.
As of February 15, 2005, Samson employed approximately 1,100 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 the General Partner, see "Item
10. Directors and Executive Officers of the General Partner."
The General Partner's and the Partnerships' principal place of business is
located at Samson Plaza, Two West Second Street, Tulsa, Oklahoma 74103, and
their telephone number is (918) 583-1791 or (888) 436-3963 [(888) GEODYNE].
Pursuant to the terms of the partnership agreements for the Partnerships
(the "Partnership Agreements") the Partnerships were scheduled to terminate on
the dates indicated in the "Initial Termination Date" column of the following
chart. However, the Partnership Agreements provide that the General Partner may
extend the term of each Partnership for up to five periods of two years each. As
of the date of this Annual Report on Form 10-K ("Annual Report"), the General
Partner has extended the term of the Partnerships for the third extension
period. Therefore, the Partnerships are currently scheduled to terminate on the
dates indicated in the "Current Termination Date" column of the following chart.
Initial Extensions Current
Partnership Termination Date Exercised Termination Date
----------- ------------------ --------- -----------------
III-A November 22, 1999 3 November 22, 2005
III-B January 24, 2000 3 December 31, 2005
III-C February 28, 2000 3 December 31, 2005
III-D September 5, 2000 3 December 31, 2005
III-E December 26, 2000 3 December 31, 2005
III-F March 7, 2001 3 December 31, 2005
The General Partner has not determined whether it will further extend the
term of any Partnership.
Funding
Although the Partnership Agreements permit the Partnerships to incur
borrowings, operations and expenses are currently funded out of each
Partnership's revenues from oil and gas sales. The General Partner may, but is
not required to, advance funds to a Partnership for the same purposes for which
Partnership borrowings are authorized.
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Principal Products Produced and Services Rendered
The Partnerships' sole business is the production of, and related
incidental development of, oil and gas. The Partnerships do not refine or
otherwise process crude oil and condensate. The Partnerships do not hold any
patents, trademarks, licenses, or concessions and are not a party to any
government contracts. The Partnerships have no backlog of orders and do not
participate in research and development activities. The Partnerships are not
presently encountering shortages of oilfield tubular goods, compressors,
production material, or other equipment. However, substantial increases in the
price of steel may increase the costs of any future workover, recompletion or
drilling activities conducted by the Partnerships.
Competition and Marketing
The primary source of liquidity and Partnership cash distributions comes
from the net revenues generated from the sale of oil and gas produced from the
Partnerships' oil and gas properties. The level of net revenues is highly
dependent upon the total volumes of oil and natural gas sold. Oil and gas
reserves are depleting assets and will experience production declines over time,
thereby likely resulting in reduced net revenues. The level of net revenues is
also highly dependent upon the prices received for oil and gas sales, which
prices have historically been very volatile and may continue to be so.
Additionally, lower oil and natural gas prices may reduce the amount of
oil and gas that is economic to produce and reduce the Partnerships' revenues
and cash flow. Various factors beyond the Partnerships' control will affect
prices for oil and natural gas, such as:
* Worldwide and domestic supplies of oil and natural gas;
* The ability of the members of the Organization of Petroleum Exporting
Countries ("OPEC") to agree upon and maintain oil prices and production
quotas;
* Political instability or armed conflict in oil-producing regions or
around major shipping areas;
* The level of consumer demand and overall economic activity;
* The competitiveness of alternative fuels;
* Weather conditions;
* The availability of pipelines for transportation; and
* Domestic and foreign government regulations and taxes.
It is not possible to predict the future direction of oil or natural gas
prices or whether the above discussed trends will remain. Operating costs,
including General and Administrative Expenses, may not decline over time or may
experience only a gradual decline, thus adversely affecting net revenues as
either production or oil and natural gas prices decline. In any
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particular period, net revenues may also be affected by either the receipt of
proceeds from property sales or the incursion of additional costs as a result of
well workovers, recompletions, new well drilling, and other events.
Significant Customers
The following customers accounted for ten percent or more of the
Partnerships' oil and gas sales during the year ended December 31, 2004:
Partnership Purchaser Percentage
----------- ------------------------ ----------
III-A Eaglwing Trading, Inc.
("Eaglwing") 26.9%
Gulfterra Central Point
Allocation ("Gulfterra") 12.2%
III-B Eaglwing 33.8%
Gulfterra 11.0%
III-C Duke Energy Field Services,
Inc.("Duke") 18.3%
Cinergy Marketing ("Cinergy") 14.5%
ONEOK Texas Energy Resources
("ONEOK") 13.4%
ONEOK Field Services Company
("ONEOK FSC") 13.3%
Enogex Services Corporation 11.5%
III-D Cinergy 19.1%
ONEOK 18.0%
Eaglwing 16.2%
Duke 14.1%
ONEOK FSC 10.8%
III-E Eaglwing 24.4%
Duke 15.1%
Mountain Gas Resources, Inc.
("Mountain") 13.5%
Sempra Energy Trading Corp.
("Sempra") 11.6%
Hunt Crude Oil Supply Company 10.4%
III-F Mountain 23.1%
Sempra 19.8%
Eaglwing 18.4%
Duke 14.7%
In the event of interruption of purchases by one or more of the
Partnerships' significant customers or the cessation or material change in
availability of open access transportation by
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the Partnerships' pipeline transporters, the Partnerships may encounter
difficulty in marketing their gas and in maintaining historic sales levels.
Management does not expect any of its open access transporters to seek
authorization to terminate their transportation services. Even if the services
were terminated, management believes that alternatives would be available
whereby the Partnerships would be able to continue to market their gas.
The Partnerships' principal customers for crude oil production are
refiners and other companies which have pipeline facilities near the producing
properties of the Partnerships. In the event pipeline facilities are not
conveniently available to production areas, crude oil is usually trucked by
purchasers to storage facilities.
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 Partnerships 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 Partnerships. Although virtually all of the Partnerships' 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 Partnerships' 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. 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 Partnerships' 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
-8-
noncompliance, may increase the cost of the Partnerships' operations or may
affect the Partnerships' 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.
Insurance Coverage
The Partnerships 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 Partnerships maintain insurance coverage as is
customary for entities of a similar size engaged in operations similar to that
of the Partnerships, but losses can occur from uninsurable risks or in amounts
in excess of existing insurance coverage. In particular, many types of pollution
and contamination can exist, undiscovered, for long periods of time and can
result in substantial environmental liabilities which are not insured. The
occurrence of an event which is not fully covered by insurance could have a
material adverse effect on the Partnerships' financial condition and results of
operations.
ITEM 2. PROPERTIES
Well Statistics
The following table sets forth the number of productive wells of the
Partnerships as of December 31, 2004.
Well Statistics(1)
As of December 31, 2004
Number of Gross Wells(2) Number of Net Wells(3)
-------------------------- -------------------------
P/ship Total Oil Gas Total Oil Gas
- -------- ----- --- --- ------ ----- -----
III-A 218 50 168 13.38 2.50 10.88
III-B 188 41 147 8.37 3.31 5.06
III-C 223 41 182 23.38 6.52 16.86
III-D 127 43 84 12.82 5.19 7.63
III-E 155 10 145 23.49 1.85 21.64
III-F 377 270 107 16.50 6.45 10.05
- ----------
(1) The designation of a well as an oil well or gas well is made by the
General Partner 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 in this Annual Report, "gross well" refers to a well in which a
working interest is owned; accordingly, the number of gross wells is the
total number of wells in which a working interest is owned.
-9-
(3) As used in 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.
Drilling Activities
During the year ended December 31, 2004, the Partnerships directly or
indirectly participated in the drilling activities described below.
County/ Working Revenue
Well Name Parish St. Interest Interest Type Status
- --------- ------- --- -------- -------- ---- ------
III-A P/ship
- ------------
Lorenz #7-7 Washita OK - .0005 Gas Producing
Rancho Blanco Webb TX - .0062 Gas Producing
#30
Tribal C 4B Rio Arriba NM - .0003 Gas Producing
Jenney #1B Rio Arriba NM - .0016 N/A In progress
Hoyt #2C Rio Arriba NM - .0002 N/A Shut-in
(MV/Dakota)
III-B P/ship
- ------------
Lorenz #7-7 Washita OK - .0003 Gas Producing
Rancho Blanco Webb TX - .0029 Gas Producing
#30
Tribal C 4B Rio Arriba NM - .0001 Gas Producing
Jenney #1B Rio Arriba NM - .0007 N/A In progress
Hoyt #2C Rio Arriba NM - .0001 N/A Shut-in
(MV/Dakota)
III-C P/ship
- ------------
Lawles #1-21 Caddo OK - .0019 Gas Producing
Thomas #4-5 Harper OK - .0004 Gas Shut-in
Pinkerton #1-6 Blaine OK .0046 .0046 Gas Producing
Sophia #2 Wheeler TX - .0031 Gas Producing
Shonda #1-14 Grady OK - .0032 Gas Producing
(RY)
Fresca #1-24 Roger OK - .0049 Gas Producing
Mills
BK #5-11 Washita OK - .0002 Gas Producing
Mickey #3-34 Pittsburg OK .0015 .0015 Gas Producing
Pluto #3-26 Pittsburg OK .0015 .0015 Gas Producing
Greer #1 Pittsburg OK .0139 .0109 Gas Shut-in
Yates #1-33 Pittsburg OK .0078 .0078 Gas Shut-in
Mickey #2-34 Pittsburg OK .0015 .0015 Gas Producing
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Verner #1-3(RY) Pittsburg OK - .0037 Gas Producing
McWilliams Pittsburg OK - .0003 Gas Producing
No. 1-23
Viets, #2 N Noble OK .0040 .0040 Oil In progress
Summers #1-27D Hughes OK - .0029 Gas Producing
Summers #1H-27 Hughes OK - .0029 Gas Shut-in
Sellers #3-35 Hughes OK - .0043 Gas Producing
Davis Garry 20 Kay OK - .0008 Oil Producing
(RY)
Davis Garry 21 Kay OK - .0008 Oil Producing
(RY)
Rancho Blanco Webb TX - .0012 Gas Producing
#30
Loving 1 State Eddy NM - .0103 Gas Producing
#4
Tribal C 4B Rio Arriba NM - .0001 Gas Producing
Jenney #1B Rio Arriba NM - .0003 N/A Producing
Lulu #1-22 Stephens OK .1323 .1072 Gas Producing
Renete #3-25 Stephens OK - .0003 Gas Producing
(RY)
Hoyt #2C Rio Arriba NM - .0000* N/A Shut-in
(MV/Dakota)
Higgins #2H-10 Roger OK - .0010 Gas Producing
Mills
Wooley Carlene Roger OK - .0001 Gas Producing
4 #1 Mills
III-D P/ship
- ------------
Lawles #1-21 Caddo OK - .0003 Gas Producing
Thomas #4-5 Harper OK - .0001 Gas Shut-in
Pinkerton #1-6 Blaine OK .0007 .0007 Gas Producing
Sophia #2 Wheeler TX - .0026 Gas Producing
Shonda #1-14 Grady OK - .0005 Gas Producing
(RY)
Fresca #1-24 Roger OK - .0007 Gas Producing
Mills
BK #5-11 Washita OK - .0000* Gas Producing
Mickey #3-34 Pittsburg OK .0002 .0002 Gas Producing
Pluto #3-26 Pittsburg OK .0002 .0002 Gas Producing
Greer #1 Pittsburg OK .0020 .0016 Gas Shut-in
Yates #1-33 Pittsburg OK .0011 .0011 Gas Shut-in
Mickey #2-34 Pittsburg OK .0002 .0002 Gas Producing
Verner #1-3(RY) Pittsburg OK - .0005 Gas Producing
McWilliams Pittsburg OK - .0000* Gas Producing
#1-23
Viets, #2 N Noble OK .0006 .0006 Oil In progress
Summers #1-27D Hughes OK - .0004 Gas Producing
Summers #1H-27 Hughes OK - .0004 Gas Shut-in
Sellers #3-35 Hughes OK - .0006 Gas Producing
Davis Garry 20 Kay OK - .0001 Oil Producing
(RY)
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Davis Garry 21 Kay OK - .0001 Oil Producing
(RY)
Loving 1 State Eddy NM - .0086 Gas Producing
#4
Lulu #1-22 Stephens OK .0189 .0154 Gas Producing
Renete #3-25 Stephens OK - .0017 Gas Producing
(RY)
Higgins #2H-10 Roger OK - .0002 Gas Producing
Mills
Wooley Carlene Roger OK - .0000* Gas Producing
4 #1 Mills
III-E P/ship
- ------------
Hay Reservoir Sweetwater WY - .0026 Gas Producing
Unit #83
Hay Reservoir Sweetwater WY - .0026 Gas Producing
Unit #84
Debrugge #1 Sweetwater WY - .0266 Gas Producing
Hayden 5175-27- Campbell WY - .0023 Gas Shut-in
11WA
St 5175-16-11CA Campbell WY - .0000* Gas Shut-in
Hayden 5175-27 Campbell WY - .0023 Oil Shut-in
43CA
St 5175-16-23CA Campbell WY - .0000* N/A Shut-in
St 5175-16-31CA Campbell WY - .0000* N/A Shut-in
St 5175-16-33CA Campbell WY - .0000* N/A Shut-in
St 5175-16-43CA Campbell WY - .0000* N/A Shut-in
St 5175-16-41CA Campbell WY - .0000* N/A Shut-in
St 5175-16-21CA Campbell WY - .0000* N/A Shut-in
St 5175-16-13CA Campbell WY - .0000* N/A Shut-in
St 5175-16-13WA Campbell WY - .0000* N/A Shut-in
St 5175-16-21WA Campbell WY - .0000* N/A Shut-in
St 5175-16-31WA Campbell WY - .0000* N/A Shut-in
St 5175-16-33WA Campbell WY - .0000* N/A Shut-in
St 5175-16-41WA Campbell WY - .0000* N/A Shut-in
St 5175-16-43WA Campbell WY - .0000* N/A Shut-in
III-F P/ship
- ------------
Hay Reservoir Sweetwater WY - .0022 Gas Producing
Unit #83
Hay Reservoir Sweetwater WY - .0022 Gas Producing
Unit #84
Debrugge #1 Sweetwater WY - .0223 Gas Producing
- ---------------
*Revenue interest is less than 0.00005.
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Oil and Gas Production, Revenue, and Price History
The following tables set 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 Partnerships,
revenues attributable to such production, and certain price and cost
information. As used in the following tables, direct operating expenses include
lease operating expenses and production taxes. In addition, gas production is
converted to oil 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.
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Net Production Data
III-A Partnership
-----------------
Year Ended December 31,
-------------------------------------
2004 2003 2002
---------- ---------- ----------
Production:
Oil (Bbls) 37,123 45,080 54,340
Gas (Mcf) 460,303 516,905 908,912
Oil and gas sales:
Oil $1,481,826 $1,336,984 $1,316,966
Gas 2,656,074 2,702,323 2,558,132
--------- --------- ---------
Total $4,137,900 $4,039,307 $3,875,098
========= ========= =========
Total direct operating
expenses $ 834,758 $ 836,517 $ 915,252
========= ========= =========
Direct operating expenses
as a percentage of oil
and gas sales 20.2% 20.7% 23.6%
Average sales price:
Per barrel of oil $39.92 $29.66 $24.24
Per Mcf of gas 5.77 5.23 2.81
Direct operating expenses
per equivalent Bbl of
oil $ 7.33 $ 6.37 $ 4.45
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Net Production Data
III-B Partnership
-----------------
Year Ended December 31,
-------------------------------------
2004 2003 2002
---------- ---------- ----------
Production:
Oil (Bbls) 25,395 31,275 39,042
Gas (Mcf) 190,781 243,753 486,057
Oil and gas sales:
Oil $1,013,900 $ 931,510 $ 949,685
Gas 1,116,553 1,276,052 1,326,476
--------- --------- ---------
Total $2,130,453 $2,207,562 $2,276,161
========= ========= =========
Total direct operating
expenses $ 486,490 $ 509,231 $ 622,936
========= ========= =========
Direct operating expenses
as a percentage of oil
and gas sales 22.8% 23.1% 27.4%
Average sales price:
Per barrel of oil $39.93 $29.78 $24.32
Per Mcf of gas 5.85 5.24 2.73
Direct operating expenses
per equivalent Bbl of
oil $ 8.51 $ 7.08 $ 5.19
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Net Production Data
III-C Partnership
-----------------
Year Ended December 31,
-------------------------------------
2004 2003 2002
---------- ---------- ----------
Production:
Oil (Bbls) 9,551 13,872 14,716
Gas (Mcf) 548,555 668,059 817,975
Oil and gas sales:
Oil $ 371,357 $ 416,104 $ 361,020
Gas 2,963,161 3,185,294 2,379,868
--------- --------- ---------
Total $3,334,518 $3,601,398 $2,740,888
========= ========= =========
Total direct operating
expenses $ 859,862 $ 868,275 $ 858,126
========= ========= =========
Direct operating expenses
as a percentage of oil
and gas sales 25.8% 24.1% 31.3%
Average sales price:
Per barrel of oil $38.88 $30.00 $24.53
Per Mcf of gas 5.40 4.77 2.91
Direct operating expenses
per equivalent Bbl of
oil $ 8.52 $ 6.93 $ 5.68
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Net Production Data
III-D Partnership
-----------------
Year Ended December 31,
-------------------------------------
2004 2003(1) 2002(1)
---------- ---------- ----------
Production:
Oil (Bbls) 8,411 12,909 10,901
Gas (Mcf) 293,250 376,825 485,485
Oil and gas sales:
Oil $ 318,494 $ 365,101 $ 263,604
Gas 1,576,403 1,749,495 1,359,890
--------- --------- ---------
Total $1,894,897 $2,114,596 $1,623,494
========= ========= =========
Total direct operating
expenses $ 494,353 $ 528,430 $ 560,114
========= ========= =========
Direct operating expenses
as a percentage of oil
and gas sales 26.1% 25.0% 34.5%
Average sales price:
Per barrel of oil $37.87 $28.28 $24.18
Per Mcf of gas 5.38 4.64 2.80
Direct operating expenses
per equivalent Bbl of
oil $ 8.63 $ 6.98 $ 6.10
- ----------
(1) These amounts have been restated to reflect the sale of the Jay Field
during 2004 as a discontinued operation. See Part II, Item 7 for more
information about this discontinued operation.
-17-
Net Production Data
III-E Partnership
-----------------
Year Ended December 31,
---------------------------------------
2004 2003(1) 2002(1)
---------- ---------- ----------
Production:
Oil (Bbls) 22,653 32,768 31,288
Gas (Mcf) 720,487 779,623 890,381
Oil and gas sales:
Oil $ 834,883 $ 882,702 $ 719,417
Gas 3,798,830 3,589,841 2,139,665
--------- --------- ---------
Total $4,633,713 $4,472,543 $2,859,082
========= ========= =========
Total direct operating
expenses $1,359,631 $1,325,795 $1,284,887
========= ========= =========
Direct operating expenses
as a percentage of oil
and gas sales 29.3% 29.6% 44.9%
Average sales price:
Per barrel of oil $36.86 $26.94 $22.99
Per Mcf of gas 5.27 4.60 2.40
Direct operating expenses
per equivalent Bbl of
oil $ 9.53 $ 8.15 $ 7.15
- ----------
(1) These amounts have been restated to reflect the sale of the Jay Field
during 2004 as a discontinued operation. See Part II, Item 7 for more
information about this discontinued operation.
-18-
Net Production Data
III-F Partnership
-----------------
Year Ended December 31,
-------------------------------------
2004 2003 2002
---------- ---------- ----------
Production:
Oil (Bbls) 20,252 20,685 23,209
Gas (Mcf) 408,746 412,842 503,895
Oil and gas sales:
Oil $ 794,329 $ 598,509 $ 529,406
Gas 2,147,403 1,881,269 1,107,352
--------- --------- ---------
Total $2,941,732 $2,479,778 $1,636,758
========= ========= =========
Total direct operating
expenses $ 726,687 $ 754,502 $ 603,358
========= ========= =========
Direct operating expenses
as a percentage of oil
and gas sales 24.7% 30.4% 36.9%
Average sales price:
Per barrel of oil $39.22 $28.93 $22.81
Per Mcf of gas 5.25 4.56 2.20
Direct operating expenses
per equivalent Bbl of
oil $ 8.22 $ 8.43 $ 5.63
Proved Reserves and Net Present Value
The following table sets forth each Partnership's estimated proved oil and
gas reserves and net present value therefrom as of December 31, 2004. The
schedule of quantities of proved oil and gas reserves was prepared by the
General Partner in accordance with the rules prescribed by the Securities and
Exchange Commission (the "SEC"). Certain reserve information was reviewed by
Ryder Scott Company, L.P. ("Ryder Scott"), an independent petroleum engineering
firm. 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
-19-
valorem taxes, and operating expenses) and estimated future development costs,
discounted at 10% per annum. Net present value attributable to the Partnerships'
proved reserves was calculated on the basis of current costs and prices at
December 31, 2004. Such prices were not escalated except in certain
circumstances where escalations were fixed and readily determinable in
accordance with applicable contract provisions. Oil and gas prices at December
31, 2004 ($43.36 per barrel and $6.02 per Mcf, respectively) were higher than
the prices in effect on December 31, 2003 ($29.25 per barrel and $5.77 per Mcf,
respectively). This increase in oil and gas prices has caused the estimates of
remaining economically recoverable reserves, as well as the values placed on
said reserves, at December 31, 2004 to be higher than such estimates and values
at December 31, 2003. The prices used in calculating the net present value
attributable to the Partnerships' proved reserves do not necessarily reflect
market prices for oil and gas production subsequent to December 31, 2004. There
can be no assurance that the prices used in calculating the net present value of
the Partnerships' proved reserves at December 31, 2004 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.
Proved Reserves and
Net Present Values
From Proved Reserves
As of December 31, 2004(1)
III-A Partnership:
-----------------
Estimated proved reserves:
Gas (Mcf) 3,772,737
Oil and liquids (Bbls) 123,403
Net present value (discounted at
10% per annum) $12,009,256
-20-
III-B Partnership:
-----------------
Estimated proved reserves:
Gas (Mcf) 1,557,071
Oil and liquids (Bbls) 74,694
Net present value (discounted at
10% per annum) $ 5,576,342
III-C Partnership:
-----------------
Estimated proved reserves:
Gas (Mcf) 4,632,503
Oil and liquids (Bbls) 81,674
Net present value (discounted at
10% per annum) $11,292,927
III-D Partnership:
-----------------
Estimated proved reserves:
Gas (Mcf) 2,409,961
Oil and liquids (Bbls) 81,073
Net present value (discounted at
10% per annum) $ 6,265,244
III-E Partnership:
-----------------
Estimated proved reserves:
Gas (Mcf) 6,440,079
Oil and liquids (Bbls) 158,508
Net present value (discounted at
10% per annum) $17,294,504
III-F Partnership:
-----------------
Estimated proved reserves:
Gas (Mcf) 4,140,725
Oil and liquids (Bbls) 314,866
Net present value (discounted at
10% per annum) $13,190,015
- ----------
(1) Includes certain gas balancing adjustments which cause the gas volumes and
net present values to differ from the reserve reports which were prepared
by the General Partner and reviewed by Ryder Scott.
-21-
No estimates of the proved reserves of the Partnerships comparable to
those included herein have been included in reports to any federal agency other
than the SEC. Additional information relating to the Partnerships' proved
reserves is contained in Note 4 to the Partnerships' financial statements,
included in Item 8 of this Annual Report.
Significant Properties
The following table sets forth the number and percent of each
Partnership's total wells which are operated by affiliates of the Partnerships
as of December 31, 2004:
Operated Wells
---------------------------------------
Partnership Number Percent
----------- ------ -------
III-A 21 7%
III-B 3 1%
III-C 120 23%
III-D 117 32%
III-E 46 19%
III-F 27 7%
The following tables set forth certain well and reserve information as of
December 31, 2004 for the basins in which the Partnerships own a significant
amount of oil and gas properties. The tables contain the following information
for each significant basin: (i) the number of gross wells and net wells, (ii)
the number of wells in which only a non-working interest is owned, (iii) the
Partnership's total number of wells, (iv) the number of wells operated by the
Partnership's affiliates, (v) estimated proved oil reserves, (vi) estimated
proved gas reserves, and (vii) the present value (discounted at 10% per annum)
of estimated future net cash flow.
The Anadarko Basin is located in western Oklahoma and the Texas panhandle.
The Gulf Coast Basin is located in southern Louisiana and southeast Texas, while
the Mid-Gulf Coast Basin covers Mississippi and southern Alabama. The Las Animas
Arch Basin straddles east Colorado and northwest Kansas. Southern Oklahoma
contains the Southern Oklahoma Folded Belt Basin. The Green River Basin is
located in southern Wyoming and northwest Colorado. The Permian Basin straddles
west Texas and southeast New Mexico.
-22-
Significant Properties as of December 31, 2004
----------------------------------------------
Wells
Operated by
Affiliates Oil Gas
Gross Net Other Total ------------ Reserves Reserves Present
Basin Wells Wells Wells(1) Wells Number %(2) (Bbl) (Mcf) Value
- ------------------ ------ ------- -------- ------ ------ ---- -------- --------- ----------
III-A Partnership:
Gulf Coast 85 6.65 55 140 4 3% 104,297 1,376,164 $6,185,469
Anadarko 38 2.30 22 60 17 28% 5,509 1,630,152 4,171,782
III-B Partnership:
Gulf Coast 81 3.63 55 136 - - 68,140 680,668 $3,504,020
Anadarko 43 2.58 13 56 3 5% 1,668 497,726 1,255,399
III-C Partnership:
Anadarko 58 6.41 66 124 28 23% 5,989 2,354,235 $5,652,461
Southern Okla.
Folded Belt 44 8.43 22 66 24 36% 51,576 1,352,790 3,707,048
Permian 28 7.33 19 47 40 85% 22,861 607,913 1,056,784
III-D Partnership:
Anadarko 36 3.57 66 102 28 27% 2,572 1,781,148 $4,274,496
Southern Okla.
Folded Belt 38 2.21 20 58 21 36% 44,894 143,254 842,353
Permian 28 3.47 19 47 40 85% 18,911 493,090 836,039
- ---------------------
(1) Wells in which only a non-working (e.g. royalty) interest is owned.
(2) Percentage of wells in the applicable basin which are operated by affiliates
of the Partnerships.
-23-
Significant Properties as of December 31, 2004
----------------------------------------------
Wells
Operated by
Affiliates Oil Gas
Gross Net Other Total ------------ Reserves Reserves Present
Basin Wells Wells Wells(1) Wells Number %(2) (Bbl) (Mcf) Value
- ------------------ ------ ------- -------- ------ ------ ---- --------- --------- ----------
III-E Partnership:
Green River 56 4.29 20 76 - - 19,589 2,874,864 $6,897,336
Gulf Coast 35 4.07 9 44 4 9% 13,073 1,013,490 3,026,265
Anadarko 22 5.27 4 26 19 73% 9,760 1,028,850 2,246,822
East Texas 3 1.06 1 4 3 75% 2,739 887,761 2,002,426
Mid-Gulf Coast 10 1.52 2 12 - - 104,718 1,013 1,827,633
III-F Partnership:
Green River 56 3.60 20 76 - - 16,450 2,417,798 $5,802,018
Las Animas Arch 66 1.73 - 66 - - 158,088 275,543 2,680,324
Anadarko 27 5.84 4 31 24 77% 19,348 940,296 2,103,208
- --------------------
(1) Wells in which only a non-working (e.g. royalty) interest is owned.
(2) Percentage of wells in the applicable basin which are operated by affiliates
of the Partnerships.
-24-
Title to Oil and Gas Properties
Management believes that the Partnerships have satisfactory title to their
oil and gas properties. Record title to all of the Partnerships' properties is
held by either the Partnerships or Geodyne Nominee Corporation, an affiliate of
the General Partner.
Title to the Partnerships' 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 Partnerships' interest therein or materially interfere with their use in the
operation of the Partnerships' business.
ITEM 3. LEGAL PROCEEDINGS
A lawsuit styled Robert W. Scott, Individually and as Managing Member of
R.W. Scott Investments, LLC v. Samson Resources Company, Case No. C-01-385, was
filed in the District Court of Sweetwater County, Wyoming on June 29, 2001. The
lawsuit seeks class action certification and alleges that Samson deducted from
its payments to royalty and overriding royalty owners certain charges which were
improper under the Wyoming royalty payment statutes. A number of these royalty
and overriding royalty payments burdened the interests of the Partnerships. In
February 2003, Samson made a supplemental payment to the royalty and overriding
royalty interest owners who were potential class members of amounts which were
then thought to have been improperly deducted plus statutory interest thereon.
The applicable portions of these refunds were recouped from the Partnerships in
the first quarter of 2003 as follows:
Partnership Amount
----------- ------------
III-A $ 5,380
III-B 3,548
III-C -
III-D -
III-E 122,289
III-F 102,690
The lawsuit also alleges that Samson's check stubs did not fully comply with the
Wyoming Royalty Payment Act. Samson intends to vigorously defend this claim.
Except as set forth above, to the knowledge of the General Partner,
neither the General Partner nor the Partnerships or their properties are subject
to any litigation, the results of
-25-
which would have a material effect on the Partnerships' or the General Partner'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 any
Partnership during 2004.
PART II
ITEM 5. MARKET FOR UNITS AND RELATED LIMITED PARTNER MATTERS
As of March 3, 2005, the number of Units outstanding and the approximate
number of Limited Partners of record in the Partnerships were as follows:
Number of Number of
Partnership Units Limited Partners
----------- --------- ----------------
III-A 263,976 1,130
III-B 138,336 670
III-C 244,536 1,060
III-D 131,008 560
III-E 418,266 1,750
III-F 221,484 900
Units were initially sold for a price of $100. Units are not traded on any
exchange and there is no public trading market for them. The General Partner is
aware of certain transfers of Units between unrelated parties, some of which are
facilitated by secondary trading firms and matching services. In addition, as
further described below, the General Partner is aware of certain "4.9% Tender
Offers" which have been made for the Units. The General Partner believes that
the transfers between unrelated parties have been limited and sporadic in number
and volume. Other than trades facilitated by certain secondary trading firms and
matching services, no organized trading market for Units exists and none is
expected to develop. Due to the nature of these transactions, the General
Partner has no verifiable information regarding prices at which Units have been
transferred. Further, a transferee may not become a substitute Limited Partner
without the consent of the General Partner.
Pursuant to the terms of the Partnership Agreements, the General Partner
is obligated to annually issue a repurchase offer which is based on the
estimated future net revenues from the Partnerships' reserves and is calculated
pursuant to the terms of the Partnership Agreements. Such repurchase offer is
recalculated monthly in order to reflect cash distributions to
-26-
the Limited Partners and extraordinary events. The following table sets forth
the General Partner's repurchase offer per Unit as of the periods indicated. For
purpose of this Annual Report, a Unit represents an initial subscription of $100
to a Partnership.
Repurchase Offer Prices
-----------------------
2003 2004 2005
------------------------- ------------------------- ----
1st 2nd 3rd 4th 1st 2nd 3rd 4th 1st
P/ship Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr.
- ------ ---- ---- ---- ---- ---- ---- ---- ---- ----
III-A $16 $14 $20 $18 $16 $14 $23 $20 $18
III-B 16 13 17 14 13 11 20 17 15
III-C 16 14 26 24 22 20 24 22 20
III-D 21 18 28 25 23 22 23 21 20
III-E 24 23 22 21 19 18 18 17 16
III-F 18 18 26 24 23 21 25 24 22
In addition to this repurchase offer, some of the Partnerships have been
subject to "4.9% tender offers" from several third parties. The General Partner
does not know the terms of these offers or the prices received by the Limited
Partners who accepted these offers.
Cash Distributions
Cash distributions are primarily dependent upon a Partnership's cash
receipts from the sale of oil and gas production and cash requirements of the
Partnership. Distributable cash is determined by the General Partner at the end
of each calendar quarter and distributed to the Limited Partners within 45 days
after the end of the quarter. Distributions are restricted to cash on hand less
amounts required to be retained out of such cash as determined in the sole
judgment of the General Partner to pay costs, expenses, or other Partnership
obligations whether accrued or anticipated to accrue. In certain instances, the
General Partner may not distribute the full amount of cash receipts which might
otherwise be available for distribution in an effort to equalize or stabilize
the amounts of quarterly distributions. Any available amounts not distributed
are invested and the interest or income thereon is for the accounts of the
Limited Partners.
The following is a summary of cash distributions paid to the Limited
Partners during 2003, 2004, and the first quarter of 2005:
-27-
Cash Distributions
-----------------
2003
-----------------------------------------
1st 2nd 3rd 4th
P/ship Qtr. Qtr. Qtr. Qtr.
------ ----- ----- ----- -----
III-A $1.78 $2.39 $3.21 $2.51
III-B 1.85 2.41 3.05 2.45
III-C 1.07 2.06 2.56 2.45
III-D 1.26 2.63 3.20 2.46
III-E .64 .87 1.91 1.68
III-F .74 .70 1.72 1.56
2004 2005
----------------------------------------- -----
1st 2nd 3rd 4th 1st
P/ship Qtr. Qtr. Qtr. Qtr. Qtr.
------ ----- ----- ----- ----- -----
III-A $1.81 $2.13 $2.20 $2.72 $2.58
III-B 1.64 1.67 1.89 2.43 2.49
III-C 1.79 1.74 1.65 1.89 1.36
III-D 2.15 1.68 2.90(1) 1.77 1.39
III-E 2.06 .44 3.60(1) .62 .82
III-F 1.35 1.55 1.50 1.40 1.91
- -------------------
(1) Includes proceeds from the sale of all of the III-D and III-E
Partnerships' interests in the Jay-Little Escambia Creek Field. See Part
II, Item 7 for more information about this discontinued operation.
ITEM 6. SELECTED FINANCIAL DATA
The following tables present selected financial data for the Partnerships.
This data should be read in conjunction with the financial statements of the
Partnerships and the respective notes thereto, included elsewhere in this Annual
Report. See "Item 8. Financial Statements and Supplementary Data."
-28-
Selected Financial Data
III-A Partnership
-----------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
Oil and Gas Sales $4,137,900 $4,039,307 $3,875,098 $5,425,163 $4,111,261
Net Income:
Limited Partners 2,534,550 2,419,111 1,822,932 3,211,072 2,424,492
General Partner 297,437 286,852 256,987 405,019 275,300
Total 2,831,987 2,705,963 2,079,919 3,616,091 2,699,792
Limited Partners' Net
Income per Unit 9.60 9.16 6.91 12.16 9.18
Limited Partners' Cash
Distributions per
Unit 8.86 9.89 8.88 14.66 6.42
Total Assets 2,577,310 2,357,510 2,465,350 3,086,819 3,585,623
Partners' Capital
(Deficit):
Limited Partners 2,410,880 2,213,330 2,405,219 2,927,287 3,587,215
General Partner ( 88,506) ( 104,097) ( 87,091) ( 114,834) ( 132,196)
Number of Units
Outstanding 263,976 263,976 263,976 263,976 263,976
-29-
Selected Financial Data
III-B Partnership
-----------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
Oil and Gas Sales $2,130,453 $2,207,562 $2,276,161 $3,146,463 $2,462,438
Net Income:
Limited Partners 1,154,435 1,171,730 916,420 1,701,127 1,364,829
General Partner 219,288 227,153 216,453 348,971 264,081
Total 1,373,723 1,398,883 1,132,873 2,050,098 1,628,910
Limited Partners' Net
Income per Unit 8.35 8.47 6.62 12.30 9.87
Limited Partners' Cash
Distributions per
Unit 7.63 9.76 9.39 14.44 7.34
Total Assets 1,379,422 1,270,257 1,390,931 1,830,746 2,069,748
Partners' Capital
(Deficit):
Limited Partners 1,277,659 1,178,224 1,357,494 1,741,074 2,037,947
General Partner ( 58,429) ( 68,928) ( 48,554) ( 67,276) ( 38,756)
Number of Units
Outstanding 138,336 138,336 138,336 138,336 138,336
-30-
Selected Financial Data
III-C Partnership
-----------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
Oil and Gas Sales $3,334,518 $3,601,398 $2,740,888 $4,371,115 $4,150,431
Net Income:
Limited Partners 1,531,505 2,016,059 1,178,582 2,653,485 2,554,851
General Partner 213,797 243,670 158,236 163,926 143,251
Total 1,745,302 2,259,729 1,336,818 2,817,411 2,698,102
Limited Partners' Net
Income per Unit 6.26 8.24 4.82 10.85 10.45
Limited Partners' Cash
Distributions per
Unit 7.07 8.14 4.77 16.36 8.45
Total Assets 2,790,409 2,902,685 2,751,198 2,627,295 3,949,266
Partners' Capital
(Deficit):
Limited Partners 2,345,365 2,542,860 2,517,801 2,507,219 3,854,734
General Partner ( 136,932) ( 153,480) ( 150,636) ( 175,495) ( 152,824)
Number of Units
Outstanding 244,536 244,536 244,536 244,536 244,536
-31-
Selected Financial Data
III-D Partnership
-----------------
2004 2003(1) 2002(1) 2001(1) 2000(1)
------------ ------------ ------------ ------------ ------------
Oil and Gas Sales $1,894,897 $2,114,596 $1,623,494 $2,424,490 $2,353,421
Income (Loss) from:
Continuing Operations 1,136,358 1,335,178 776,273 1,541,967 1,554,143
Discontinued
Operations ( 86,127) 111,356 22,377 195,103 448,623
Net Income:
Limited Partners 936,644 1,293,974 705,530 1,630,013 1,893,355
General Partner 113,587 155,435 93,120 107,057 109,411
Total 1,050,231 1,449,409 798,650 1,737,070 2,002,766
Limited Partners' Net
Income per Unit 7.15 9.88 5.39 12.44 14.45
Limited Partners' Cash
Distributions per
Unit 8.50 9.55 3.75 19.36 13.21
Total Assets 1,370,609 1,731,542 1,458,550 1,157,930 1,987,262
Partners' Capital
(Deficit):
Limited Partners 951,972 1,129,328 1,086,354 872,824 1,779,811
General Partner ( 55,158) ( 47,561) ( 50,949) ( 72,956) ( 58,871)
Number of Units
Outstanding 131,008 131,008 131,008 131,008 131,008
- -------------
(1) These amounts have been restated to reflect the sale of the Jay Field
during 2004 as a discontinued operation. See Part II, Item 7 for more
information about this discontinued operation.
-32-
Selected Financial Data
III-E Partnership
-----------------
2004 2003(1) 2002(1) 2001(1) 2000(1)
------------ ------------ ------------ ------------ ------------
Oil and Gas Sales $4,633,713 $4,472,543 $2,859,082 $4,752,859 $5,183,231
Income (Loss) from:
Continuing Operations 2,599,547 2,519,727 777,174 2,722,457 4,125,509
Discontinued
Operations ( 598,888) 785,456 149,044 1,283,442 3,205,076
Net Income:
Limited Partners 1,782,244 2,940,848 798,510 3,744,610 6,952,136
General Partner 218,415 367,060 127,708 261,289 378,449
Total 2,000,659 3,307,908 926,218 4,005,899 7,330,585
Limited Partners' Net
Income per Unit 4.26 7.03 1.91 8.95 16.62
Limited Partners' Cash
Distributions per
Unit 6.72 5.10 .63 14.81 15.73
Total Assets 4,254,283 6,654,923 4,442,417 3,768,636 6,138,734
Partners' Capital
(Deficit):
Limited Partners 3,277,777 4,302,533 3,492,685 2,960,175 5,410,565
General Partner ( 316,058) ( 177,234) ( 250,684) ( 286,758) ( 240,721)
Number of Units
Outstanding 418,266 418,266 418,266 418,266 418,266
- ----------
(1) These amounts have been restated to reflect the sale of the Jay Field
during 2004 as a discontinued operation. See Part II, Item 7 for more
information about this discontinued operation.
-33-
Selected Financial Data
III-F Partnership
-----------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
Oil and Gas Sales $2,941,732 $2,479,778 $1,636,758 $2,934,300 $3,437,321
Net Income:
Limited Partners 1,694,433 1,176,685 460,816 1,782,241 2,142,067
General Partner 95,789 70,747 35,680 103,349 125,735
Total 1,790,222 1,247,432 496,496 1,885,590 2,267,802
Limited Partners' Net
Income per Unit 7.65 5.31 2.08 8.05 9.67
Limited Partners' Cash
Distributions per
Unit 5.80 4.72 2.60 13.62 9.59
Total Assets 2,994,343 2,592,302 2,427,147 2,369,806 3,638,555
Partners' Capital
(Deficit):
Limited Partners 2,783,155 2,374,722 2,245,037 2,359,221 3,593,980
General Partner ( 142,055) ( 156,356) ( 159,621) ( 161,655) ( 135,914)
Number of Units
Outstanding 221,484 221,484 221,484 221,484 221,484
-34-
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 Partnerships.
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.
Discontinued Operations
The III-D and III-E Partnerships owned working interests in the Jay-Little
Escambia Creek Field in Santa Rosa County, Florida (the "Jay Field"). In May
2004, the III-D and III-E Partnerships sold all of their interests in the Jay
Field. For accounting purposes, the sale was treated as a discontinued
operation. The sales proceeds, consisting of approximately $89,000 and $632,000,
respectively, were included in the III-D and III-E Partnerships' August 15, 2004
cash distributions.
The sale of the Jay Field interests will impact the continuing future
operations of the III-D and III-E Partnerships. It is anticipated that these
Partnerships will have lower lease operating costs, lower oil and gas sales, and
a reduction in their asset retirement obligations. However, routine audits of
joint interest billings by an unaffiliated non-operator after the close date of
the sale resulted in additional expenses of approximately $76,000 and $544,000,
respectively, billed to the
-35-
III-D and III-E Partnerships. The expenses represent costs incurred before the
effective date of the sale. The reader should refer to Note 6 - Discontinued
Operations to the consolidated financial statements included in Part II, Item 8
of this Annual Report on Form 10-K for additional information regarding this
matter.
General Discussion
The following general discussion should be read in conjunction with the
analysis of results of operations provided below. The primary source of
liquidity and Partnership cash distributions comes from the net revenues
generated from the sale of oil and gas produced from the Partnerships' oil and
gas properties. The level of net revenues is highly dependent upon the prices
received for oil and gas sales, which prices have historically been very
volatile and may continue to be so. Additionally, lower oil and natural gas
prices may reduce the amount of oil and gas that is economic to produce and
reduce the Partnerships' revenues and cash flow. Various factors beyond the
Partnerships' control will affect prices for oil and natural gas, such as:
* Worldwide and domestic supplies of oil and natural gas;
* The ability of the members of the Organization of Petroleum Exporting
Countries ("OPEC") to agree upon and maintain oil prices and production
quotas;
* Political instability or armed conflict in oil-producing regions or
around major shipping areas;
* The level of consumer demand and overall economic activity;
* The competitiveness of alternative fuels;
* Weather conditions;
* The availability of pipelines for transportation; and
* Domestic and foreign government regulations and taxes.
It is not possible to predict the future direction of oil or natural gas
prices or whether the above discussed trends will remain. Operating costs,
including General and Administrative Expenses, may not decline over time or may
experience only a gradual decline, thus adversely affecting net revenues as
either production or oil and natural gas prices decline. In any particular
period, net revenues may also be affected by either the receipt of proceeds from
property sales or the incursion of additional costs as a result of well
workovers, recompletions, new well drilling, and other events.
In addition to pricing, the level of net revenues is also highly dependent
upon the total volumes of oil and natural gas sold. Oil and gas reserves are
depleting assets and will experience production declines over time, thereby
likely resulting in reduced net revenues. Despite this general trend of
declining production, several factors can cause the volumes of
-36-
oil and gas sold to increase or decrease at an even greater rate over a given
period. These factors include, but are not limited to, (i) geophysical
conditions which cause an acceleration of the decline in production, (ii) the
shutting in of wells (or the opening of previously shut-in wells) due to low oil
and gas prices (or high oil and gas prices), mechanical difficulties, loss of a
market or transportation, or performance of workovers, recompletions, or other
operations in the well, (iii) prior period volume adjustments (either positive
or negative) made by purchasers of the production, (iv) ownership adjustments in
accordance with agreements governing the operation or ownership of the well
(such as adjustments that occur at payout), and (v) completion of enhanced
recovery projects which increase production for the well. Many of these factors
are very significant as related to a single well or as related to many wells
over a short period of time. However, due to the large number of wells owned by
the Partnerships, these factors are generally not material as compared to the
normal decline in production experienced on all remaining wells.
Results of Operations
An analysis of the change in net oil and gas operations (oil and gas
sales, less lease operating expenses and production taxes), is presented in the
tables following "Results of Operations" under the heading "Average Sales
Prices, Production Volumes, and Average Production Costs." Following is a
discussion of each Partnerships' results of operations for the year ended
December 31, 2004 as compared to the year ended December 31, 2003, and for the
year ended December 31, 2003 as compared to the year ended December 31, 2002.
III-A Partnership
-----------------
Year Ended December 31, 2004 Compared
to Year Ended December 31, 2003
-------------------------------------
Total oil and gas sales increased $98,593 (2.4%) in 2004 as compared to
2003. Of this increase, approximately $381,000 and $250,000, respectively, were
related to increases in the average prices of oil and gas sold. These increases
were partially offset by decreases of approximately $236,000 and $296,000,
respectively, related to decreases in volumes of oil and gas sold. Volumes of
oil and gas sold decreased 7,957 barrels and 56,602 Mcf, respectively, in 2004
as compared to 2003. The decrease in volumes of oil sold was primarily due to
(i) normal declines in production and (ii) the shutting-in of one significant
well during late 2004 due to mechanical problems. As of the date of this Annual
Report, the shut-in well has returned
-37-
to production. The decrease in volumes of gas sold was primarily due to normal
declines in production, which was partially offset by the receipt of first
revenues on one significant well during 2004. Average oil and gas prices
increased to $39.92 per barrel and $5.77 per Mcf, respectively, in 2004 from
$29.66 per barrel and $5.23 per Mcf, respectively, in 2003.
Oil and gas production expenses (including lease operating expenses and
production taxes) remained relatively constant in 2004 and 2003. Lease operating
expenses decreased due to the decreases in volumes of oil and gas sold, but this
decrease was substantially offset by (i) an increase in production taxes
associated with the increase in oil and gas sales, (ii) an increase in
production taxes associated with the receipt of first revenues on one
significant well during 2004, and (iii) workover expenses incurred on two
significant wells during 2004. As a percentage of oil and gas sales, these
expenses decreased to 20.2% in 2004 from 20.7% in 2003.
Depreciation, depletion, and amortization of oil and gas properties
decreased $20,906 (11.2%) in 2004 as compared to 2003. This decrease was
primarily due to (i) the decreases in volumes of oil and gas sold and (ii)
upward revisions in the estimates of remaining oil and gas reserves during 2004.
These decreases were partially offset by the abandonment of one significant well
during 2004 following an unsuccessful recompletion attempt. As a percentage of
oil and gas sales, this expense decreased to 4.0% in 2004 from 4.6% in 2003.
This percentage decrease was primarily due to the dollar decrease in
depreciation, depletion, and amortization of oil and gas properties.
General and administrative expenses remained relatively constant in 2004
and 2003. As a percentage of oil and gas sales, these expenses decreased to 7.6%
in 2004 from 7.8% in 2003.
The Limited Partners have received cash distributions through December 31,
2004 totaling $38,896,701 or 147.35% of Limited Partners' capital contributions.
Year Ended December 31, 2003 Compared
to Year Ended December 31, 2002
-------------------------------------
Total oil and gas sales increased $164,209 (4.2%) in 2003 as compared to
2002. Of this increase, approximately $244,000 and $1,247,000, respectively,
were related to increases in the average prices of oil and gas sold. These
increases were partially offset by decreases of approximately $224,000 and
$1,103,000, respectively, related to decreases in volumes of oil and gas sold.
Volumes of oil and gas sold decreased 9,260 barrels and 392,007 Mcf,
respectively, in 2003 as compared to 2002. The decrease in volumes of oil sold
was primarily due to normal declines in production, which decrease was partially
-38-
offset by an increase in production during 2003 on one significant well due to
the successful workover of that well during mid 2002. The decrease in volumes of
gas sold was primarily due to (i) positive prior period gas balancing
adjustments on two significant wells during 2002, (ii) a substantial decline in
production during 2003 on one significant well following the workover of that
well during early 2002, and (iii) normal declines in production. The well with a
substantial decline in production is not expected to return to previously high
levels of production. Average oil and gas prices increased to $29.66 per barrel
and $5.23 per Mcf, respectively, in 2003 from $24.24 per barrel and $2.81 per
Mcf, respectively, in 2002.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $78,735 (8.6%) in 2003 as compared to 2002. This
decrease was primarily due to (i) a decrease in lease operating expenses
associated with the decreases in volumes of oil and gas sold, (ii) positive
prior period lease operating expense adjustments on two significant wells during
2002, and (iii) workover expenses incurred on two other significant wells during
2002. As a percentage of oil and gas sales, these expenses decreased to 20.7% in
2003 from 23.6% in 2002. This percentage decrease was primarily due to the
increases in the average prices of oil and gas sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $366,320 (66.3%) in 2003 as compared to 2002. This decrease was
primarily due to (i) the decreases in volumes of oil and gas sold, (ii) several
wells being fully depleted in 2002 due to the lack of remaining economically
recoverable reserves, and (iii) upward revisions in the estimates of remaining
oil and gas reserves at December 31, 2003. As a percentage of oil and gas sales,
this expense decreased to 4.6% in 2003 from 14.3% in 2002. This percentage
decrease was primarily due to the dollar decrease in depreciation, depletion,
and amortization of oil and gas properties.
General and administrative expenses increased $3,208 (1.0%) in 2003 as
compared to 2002. As a percentage of oil and gas sales, these expenses decreased
to 7.8% in 2003 from 8.1% in 2002.
III-B Partnership
-----------------
Year Ended December 31, 2004 Compared
to Year Ended December 31, 2003
-------------------------------------
Total oil and gas sales decreased $77,109 (3.5%) in 2004 as compared to
2003. Of this decrease, approximately $175,000 and $277,000, respectively, were
related to decreases in volumes of
-39-
oil and gas sold. These decreases were partially offset by increases of
approximately $257,000 and $118,000, respectively, related to increases in the
average prices of oil and gas sold. Volumes of oil and gas sold decreased 5,880
barrels and 52,972 Mcf, respectively, in 2004 as compared to 2003. The decrease
in volumes of oil sold was primarily due to (i) normal declines in production
and (ii) the shutting-in of one significant well during late 2004 due to
mechanical problems. As of the date of this Annual Report, the shut-in well has
returned to production. The decrease in volumes of gas sold was primarily due to
normal declines in production. Average oil and gas prices increased to $39.93
per barrel and $5.85 per Mcf, respectively, in 2004 from $29.78 per barrel and
$5.24 per Mcf, respectively, in 2003.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $22,741 (4.5%) in 2004 as compared to 2003. As a
percentage of oil and gas sales, these expenses decreased to 22.8% in 2004 from
23.1% in 2003.
Depreciation, depletion, and amortization of oil and gas properties
decreased $28,482 (22.5%) in 2004 as compared to 2003. This decrease was
primarily due to (i) the decreases in volumes of oil and gas sold and (ii)
upward revisions in the estimates of remaining oil and gas reserves during 2004.
These decreases were partially offset by the abandonment of one significant well
during 2004 following an unsuccessful recompletion attempt. As a percentage of
oil and gas sales, this expense decreased to 4.6% in 2004 from 5.7% in 2003.
This percentage decrease was primarily due to the dollar decrease in
depreciation, depletion, and amortization of oil and gas properties.
General and administrative expenses remained relatively constant in 2004
and 2003. As a percentage of oil and gas sales, these expenses increased to 8.2%
in 2004 from 8.0% in 2003.
The Limited Partners have received cash distributions through December 31,
2004 totaling $21,832,353 or 157.82% of Limited Partners' capital contributions.
Year Ended December 31, 2003 Compared
to Year Ended December 31, 2002
-------------------------------------
Total oil and gas sales decreased $68,599 (3.0%) in 2003 as compared to
2002. Of this decrease, approximately $189,000 and $661,000, respectively, were
related to decreases in volumes of oil and gas sold. These decreases were
partially offset by increases of approximately $170,000 and $611,000,
respectively, related to increases in the average prices of oil and gas sold.
Volumes of oil and gas sold decreased 7,767 barrels and 242,304 Mcf,
respectively, in 2003 as compared to 2002. The decrease in volumes of oil sold
was primarily due to normal declines in production, which decrease was partially
offset by an increase in
-40-
production during 2003 on one significant well due to the successful workover of
that well during mid 2002. The decrease in volumes of gas sold was primarily due
to (i) positive prior period gas balancing adjustments on two significant wells
during 2002, (ii) a substantial decline in production during 2003 on one
significant well following the workover of that well during early 2002, and
(iii) normal declines in production. The well with a substantial decline in
production is not expected to return to its previously high levels of
production. Average oil and gas prices increased to $29.78 per barrel and $5.24
per Mcf, respectively, in 2003 from $24.32 per barrel and $2.73 per Mcf,
respectively, in 2002.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $113,705 (18.3%) in 2003 as compared to 2002. This
decrease was primarily due to (i) a decrease in lease operating expenses
associated with the decreases in volumes of oil and gas sold, (ii) positive
prior period lease operating expense adjustments on two significant wells during
2002, and (iii) workover expenses incurred on several wells during 2002. As a
percentage of oil and gas sales, these expenses decreased to 23.1% in 2003 from
27.4% in 2002. This percentage decrease was primarily due to the increases in
the average prices of oil and gas sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $210,187 (62.5%) in 2003 as compared to 2002. This decrease was
primarily due to (i) the decreases in volumes of oil and gas sold, (ii) several
wells being fully depleted in 2002 due to the lack of remaining economically
recoverable reserves, and (iii) upward revisions in the estimates of remaining
oil and gas reserves at December 31, 2003. As a percentage of oil and gas sales,
this expense decreased to 5.7% in 2003 from 14.8% in 2002. This percentage
decrease was primarily due to the dollar decrease in depreciation, depletion,
and amortization of oil and gas properties.
General and administrative expenses increased $2,469 (1.4%) in 2003 as
compared to 2002. As a percentage of oil and gas sales, these expenses increased
to 8.0% in 2003 from 7.6% in 2002.
III-C Partnership
-----------------
Year Ended December 31, 2004 Compared
to Year Ended December 31, 2003
-------------------------------------
Total oil and gas sales decreased $266,880 (7.4%) in 2004 as compared to
2003. Of this decrease, approximately $130,000 and $570,000, respectively, were
related to decreases in volumes of
-41-
oil and gas sold. These decreases were partially offset by increases of
approximately $85,000 and $348,000, respectively, related to increases in the
average prices of oil and gas sold. Volumes of oil and gas sold decreased 4,321
barrels and 119,504 Mcf, respectively, in 2004 as compared to 2003. The decrease
in volumes of oil sold was primarily due to (i) normal declines in production
and (ii) the shutting-in of a production zone on one significant well during
late 2003. As of the date of this Annual Report, management does not expect the
shut-in zone to return to production. The decrease in volumes of gas sold was
primarily due to (i) normal declines in production and (ii) downward revisions
in the estimates of remaining gas reserves on one significant well resulting in
the III-C Partnership becoming over produced in excess of estimated ultimate
reserves, thereby increasing its gas imbalance payable. These decreases were
partially offset by the successful completion of a new well during early 2004.
Average oil and gas prices increased to $38.88 per barrel and $5.40 per Mcf,
respectively, in 2004 from $30.00 per barrel and $4.77 per Mcf, respectively, in
2003.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $8,413 (1.0%) in 2004 as compared to 2003. This
decrease was primarily due to the decreases in volumes of oil and gas sold,
which decrease was partially offset by workover expenses incurred on several
wells during 2004. As a percentage of oil and gas sales, these expenses
increased to 25.8% in 2004 from 24.1% in 2003.
Depreciation, depletion, and amortization of oil and gas properties
increased $237,997 (116.6%) in 2004 as compared to 2003. This increase was
primarily due to one significant well being fully depleted in 2004 due to the
lack of remaining reserves. This increase was partially offset by the decreases
in volumes of oil and gas sold. As a percentage of oil and gas sales, this
expense increased to 13.3% in 2004 from 5.7% in 2003. This percentage increase
was primarily due to the dollar increase in depreciation, depletion, and
amortization of oil and gas properties.
General and administrative expenses remained relatively constant in 2004
and 2003. As a percentage of oil and gas sales, these expenses increased to 8.7%
in 2004 from 8.1% in 2003.
The Limited Partners have received cash distributions through December 31,
2004 totaling $29,393,795 or 120.20% of Limited Partners' capital contributions.
Year Ended December 31, 2003 Compared
to Year Ended December 31, 2002
-------------------------------------
Total oil and gas sales increased $860,510 (31.4%) in 2003 as compared to
2002. Of this increase, approximately $1,242,000
-42-
was related to an increase in the average price of gas sold. This increase was
partially offset by a decrease of approximately $436,000 related to a decrease
in volumes of gas sold. Volumes of oil and gas sold decreased 844 barrels and
149,916 Mcf, respectively, in 2003 as compared to 2002. The decrease in volumes
of oil sold was primarily due to the shutting-in of several wells within one
unit for the latter portion of 2003 in order to perform workovers on those
wells. The operator has not yet determined when the shut-in wells will return to
production. This decrease was partially offset by an increase in production
during 2003 on another significant well due to the successful recompletion of
that well in late 2002. The decrease in volumes of gas sold was primarily due to
(i) normal declines in production and (ii) the shutting-in of two significant
wells during 2003 in order to perform workovers on those wells. One of the
shut-in wells has returned to production and the operator has not yet determined
when the other well will return to production. These decreases were partially
offset by the successful completion of one significant well in early 2003.
Average oil and gas prices increased to $30.00 per barrel and $4.77 per Mcf,
respectively, in 2003 from $24.53 per barrel and $2.91 per Mcf, respectively, in
2002.
Oil and gas production expenses (including lease operating expenses and
production taxes) increased $10,149 (1.2%) in 2003 as compared to 2002. This
increase was primarily due to (i) an increase in production taxes associated
with the increase in oil and gas sales and (ii) workover expenses incurred on
one significant well during 2003. These increases were partially offset by (i) a
decrease in lease operating expenses associated with the decreases in volumes of
oil and gas sold, (ii) workover expenses incurred on several wells during 2002,
and (iii) lower workover expenses incurred on another significant well during
2003 than similar expenses incurred on the same well during 2002. As a
percentage of oil and gas sales, these expenses decreased to 24.1% in 2003 from
31.3% in 2002. This percentage decrease was primarily due to the increases in
the average prices of oil and gas sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $73,202 (26.4%) in 2003 as compared to 2002. This decrease was
primarily due to (i) the decreases in volumes of oil and gas sold, (ii) upward
revisions in the estimates of remaining oil and gas reserves at December 31,
2003, and (iii) several wells being fully depleted in 2002 due to the lack of
remaining economically recoverable reserves. As a percentage of oil and gas
sales, this expense decreased to 5.7% in 2003 from 10.1% in 2002. This
percentage decrease was primarily due to the increases in the average prices of
oil and gas sold.
General and administrative expenses increased $2,917 (1.0%) in 2003 as
compared to 2002. As a percentage of oil and gas sales, these expenses decreased
to 8.1% in 2003 from 10.6% in 2002. This percentage decrease was primarily due
to the increase in oil and gas sales.
-43-
III-D Partnership
-----------------
Year Ended December 31, 2004 Compared
to Year Ended December 31, 2003
-------------------------------------
The following discussion contains amounts for the year 2003 which have
been restated to reflect the sale of the Jay Field during 2004 as a discontinued
operation. See Part II, Item 7 for more information about this discontinued
operation.
Total oil and gas sales decreased $219,699 (10.4%) in 2004 as compared to
2003. Of this decrease, approximately $127,000 and $388,000, respectively, were
related to decreases in volumes of oil and gas sold. These decreases were
partially offset by increases of approximately $80,000 and $215,000,
respectively, related to increases in the average prices of oil and gas sold.
Volumes of oil and gas sold decreased 4,498 barrels and 83,575 Mcf,
respectively, in 2004 as compared to 2003. The decrease in volumes of oil sold
was primarily due to (i) the shutting-in of a production zone on one significant
well during late 2003 and (ii) normal declines in production. As of the date of
this Annual Report, management does not expect the shut-in zone to return to
production. The decrease in volumes of gas sold was primarily due to (i) normal
declines in production and (ii) downward revisions in the estimates of remaining
gas reserves on one significant well resulting in the III-D Partnership becoming
over produced in excess of estimated ultimate reserves thereby increasing gas
imbalance payable. Average oil and gas prices increased to $37.87 per barrel and
$5.38 per Mcf, respectively, in 2004 from $28.28 per barrel and $4.64 per Mcf,
respectively, in 2003.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $34,077 (6.4%) in 2004 as compared to 2003. This
decrease was primarily due to (i) the decreases in volumes of oil and gas sold,
(ii) workover expenses incurred on one significant well during 2003, and (iii) a
decrease in production taxes associated with the decrease in oil and gas sales.
These decreases were partially offset by workover expenses incurred on two other
significant wells during 2004. As a percentage of oil and gas sales, these
expenses increased to 26.1% in 2004 from 25.0% in 2003.
Depreciation, depletion, and amortization of oil and gas properties
decreased $1,004 (1.0%) in 2004 as compared to 2003. This decrease was primarily
due to the decreases in volumes of oil and gas sold, which decrease was
partially offset by one significant well being fully depleted in 2004 due to the
lack of
-44-
remaining reserves. As a percentage of oil and gas sales, these expenses
increased to 5.1% in 2004 from 4.6% in 2003.
General and administrative expenses increased $3,963 (2.4%) in 2004 as
compared to 2003. As a percentage of oil and gas sales, these expenses increased
to 9.0% in 2004 from 7.9% in 2003. This percentage increase was primarily due to
the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31,
2004 totaling $16,425,669 or 125.38% of Limited Partners' capital contributions.
Year Ended December 31, 2003 Compared
to Year Ended December 31, 2002
-------------------------------------
The following discussion has been restated to reflect the sale of the Jay
Field during 2004 as a discontinued operation. See Part II, Item 7 for more
information about this discontinued operation.
Total oil and gas sales increased $491,102 (30.2%) in 2003 as compared to
2002. Of this increase, approximately $53,000 and $694,000, respectively, were
related to increases in the average prices of oil and gas sold. These increases
were partially offset by a decrease of approximately $304,000 related to a
decrease in volumes of gas sold. Volumes of oil sold increased 2,008 barrels,
while volumes of gas sold decreased 108,660 Mcf, respectively, in 2003 as
compared to 2002. The decrease in volumes of gas sold was primarily due to (i)
normal declines in production and (ii) the shutting-in of two significant wells
during 2003 in order to perform workovers on those wells. One of the shut-in
wells has returned to production and the operator has not yet determined when
the other well will return to production. These decreases were partially offset
by the successful completion of one significant well in early 2003. Average oil
and gas prices increased to $28.28 per barrel and $4.64 per Mcf, respectively,
in 2003 from $24.18 per barrel and $2.80 per Mcf, respectively, in 2002.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $31,684 (5.7%) in 2003 as compared to 2002. This
decrease was primarily due to (i) a decrease in lease operating expenses
associated with the decrease in volumes of gas sold and (ii) lower workover
expenses incurred on one significant well during 2003 than similar expenses
incurred on the same well during 2002. These decreases were partially offset by
(i) an increase in production taxes associated with the increase in oil and gas
sales and (ii) workover expenses incurred on another significant well during
2003. As a percentage of oil and gas sales, these expenses decreased to 25.0% in
2003 from 34.5% in 2002. This percentage
-45-
decrease was primarily due to the increases in the average prices of oil and gas
sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $42,301 (30.4%) in 2003 as compared to 2002. This decrease was
primarily due to (i) two significant wells being fully depleted in 2002 due to
the lack of remaining economically recoverable reserves, (ii) the decrease in
volumes of gas sold, and (iii) upward revisions in the estimates of remaining
gas reserves at December 31, 2003. As a percentage of oil and gas sales, these
expenses decreased to 4.6% in 2003 from 8.6% in 2002. This percentage decrease
was primarily due to the increases in the average prices of oil and gas sold.
General and administrative expenses increased $2,477 (1.5%) in 2003 as
compared to 2002. As a percentage of oil and gas sales, these expenses decreased
to 7.9% in 2003 from 10.2% in 2002. This percentage decrease was primarily due
to the increase in oil and gas sales.
III-E Partnership
-----------------
Year Ended December 31, 2004 Compared
to Year Ended December 31, 2003
-------------------------------------
The following discussion contains amounts for the year 2003 which have
been restated to reflect the sale of the Jay Field during 2004 as a discontinued
operation. See Part II, Item 7 for more information about this discontinued
operation.
Total oil and gas sales increased $161,170 (3.6%) in 2004 as compared to
2003. Of this increase, approximately $225,000 and $481,000, respectively, were
related to increases in the average prices of oil and gas sold. These increases
were partially offset by decreases of approximately $273,000 and $272,000,
respectively, related to decreases in volumes of oil and gas sold. Volumes of
oil and gas sold decreased 10,115 barrels and 59,136 Mcf, respectively, in 2004
as compared to 2003. The decrease in volumes of oil sold was primarily due to
(i) a negative prior period volume adjustment made by the operator on one
significant well during 2004 and (ii) normal declines in production. Average oil
and gas prices increased to $36.86 per barrel and $5.27 per Mcf, respectively,
in 2004 from $26.94 per barrel and $4.60 per Mcf, respectively, in 2003.
Oil and gas production expenses (including lease operating expenses and
production taxes) increased $33,836 (2.6%) in 2004 as compared to 2003. This
increase was primarily due to (i) a prior period production tax adjustment on
one significant unit during 2004, (ii) workover expenses incurred on two
significant
-46-
wells during 2004, and (iii) an increase in production taxes associated with the
increase in oil and gas sales. These increases were partially offset by the
decreases in volumes of oil and gas sold. As a percentage of oil and gas sales,
these expenses decreased to 29.3% in 2004 from 29.6% in 2003.
Depreciation, depletion, and amortization of oil and gas properties
decreased $24,671 (11.2%) in 2004 as compared to 2003. This decrease was
primarily due to (i) the decreases in volumes of oil and gas sold and (ii) one
significant well being fully depleted in 2003 due to the lack of remaining
reserves. These decreases were partially offset by (i) an increase in depletable
oil and gas properties primarily due to recompletion activities on two
significant wells during 2004 and (ii) one other significant well being fully
depleted in 2004 due to the lack of remaining reserves. As a percentage of oil
and gas sales, this expense decreased to 4.2% in 2004 from 4.9% in 2003. This
percentage decrease was primarily due to the dollar decrease in depreciation,
depletion, and amortization of oil and gas properties.
General and administrative expenses remained relatively constant in 2004
and 2003. As a percentage of oil and gas sales, these expenses decreased to
10.5% in 2004 from 10.9% in 2003.
The Limited Partners have received cash distributions through December 31,
2004 totaling $49,295,016 or 117.86% of Limited Partners' capital contributions.
Year Ended December 31, 2003 Compared
to Year Ended December 31, 2002
-------------------------------------
The following discussion has been restated to reflect the sale of the Jay
Field during 2004 as a discontinued operation. See Part II, Item 7 for more
information about this discontinued operation.
Total oil and gas sales increased $1,613,461 (56.4%) in 2003 as compared
to 2002. Of this increase, approximately $129,000 and $1,716,000, respectively,
were related to increases in the average prices of oil and gas sold. These
increases were partially offset by a decrease of approximately $266,000 related
to a decrease in volumes of gas sold. Volumes of oil sold increased 1,480
barrels, while volumes of gas sold decreased 110,758 Mcf in 2003 as compared to
2002. The decrease in volumes of gas sold was primarily due to (i) normal
declines in production and (ii) the shutting-in of one significant well due to
production difficulties during 2003. The operator has not yet determined when
the shut-in well will return to production. Average oil and gas prices increased
to $26.94 per barrel and $4.60 per Mcf, respectively, in 2003 from $22.99 per
barrel and $2.40 per Mcf, respectively, in 2002.
-47-
Oil and gas production expenses (including lease operating expenses and
production taxes) increased $40,908 (3.2%) in 2003 as compared to 2002. This
increase was primarily due to an increase in production taxes associated with
the increase in oil and gas sales. This increase was partially offset by a
decrease in lease operating expenses associated with the decrease in volumes of
gas sold. As a percentage of oil and gas sales, these expenses decreased to
29.6% in 2003 from 44.9% in 2002. This percentage decrease was primarily due to
the increases in the average prices of oil and gas sold.
Depreciation, depletion, and amortization of oil and gas properties
decreased $93,652 (29.7%) in 2003 as compared to 2002. This decrease was
primarily due to (i) two significant wells being fully depleted in 2002 due to
the lack of remaining economically recoverable reserves and (ii) the decrease in
volumes of gas sold. These decreases were partially offset by one significant
well being fully depleted in 2003 due to the lack of remaining economically
recoverable reserves. As a percentage of oil and gas sales, this expense
decreased to 4.9% in 2003 from 11.0% in 2002. This percentage decrease was
primarily due to the increases in the average prices of oil and gas sold.
General and administrative expenses remained relatively constant in 2003
and 2002. As a percentage of oil and gas sales, these expenses decreased to
10.9% in 2003 from 17.0% in 2002. This percentage decrease was primarily due to
the increase in oil and gas sales.
III-F Partnership
-----------------
Year Ended December 31, 2004 Compared
to Year Ended December 31, 2003
-------------------------------------
Total oil and gas sales increased $461,954 (18.6%) in 2004 as compared to
2003. Of this increase, approximately $208,000 and $285,000, respectively, were
related to increases in the average prices of oil and gas sold. Volumes of oil
and gas sold decreased 433 barrels and 4,096 Mcf, respectively, in 2004 as
compared to 2003. Average oil and gas prices increased to $39.22 per barrel and
$5.25 per Mcf, respectively, in 2004 from $28.93 per barrel and $4.56 per Mcf,
respectively, in 2003.
Oil and gas production expenses (including lease operating expenses and
production taxes) decreased $27,815 (3.7%) in 2004 as compared to 2003. This
decrease was primarily due to (i) workover expenses incurred on one significant
well during 2003 and (ii) the abandonment of another significant well in early
2003 due to severe mechanical problems. These decreases were
-48-
partially offset by an increase in production taxes associated with the increase
in oil and gas sales. As a percentage of oil and gas sales, these expenses
decreased to 24.7% in 2004