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"), Geodyne Energy Income Limited Partnership III-F (the "III-F Partnership"), and Geodyne Energy Income Limited Partnership III-G (the "III-G 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 21, 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 III-G September 20, 1991
The General Partner currently serves as general partner of 29 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 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.
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.
As limited partnerships, the Partnerships have no officers, directors, or employees. They rely instead on the personnel of the General Partner and the other Samson Companies. As of February 15, 1999, Samson employed approximately 850 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 will terminate on the following dates:
Partnership Termination Date ----------- ------------------ III-A November 28, 1999 III-B January 24, 2000 III-C February 28, 2000 III-D September 5, 2000 III-E December 26, 2000 III-F March 7, 2001 III-G September 20, 2001
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-K405 ("Annual Report"), the General Partner intends to extend the term of the III-A, III-B, and III-C Partnerships for the first two-year extension period, but has not determined whether it intends to (i) further extend the term of such Partnerships or (ii) extend the term of any other 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.
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.
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 Partnerships to produce and market oil and gas profitably depends on a number of factors that are beyond the control of the Partnerships. 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 fuels, the overall economic environment, and the availability and capacity of transportation and processing facilities. The effect of these factors on future oil and gas industry trends cannot be accurately predicted or anticipated.
The most important variable affecting the Partnerships' 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. Gas prices are currently in the lower half of the 10-year average range described above.
Substantially all of the Partnerships' 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 Partnerships' 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 Partnerships 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 a drop in Asian energy demand, oil prices over the past year have reached historically low levels, dropping to as low as approximately $9.25 per barrel. It is not known whether this trend will continue. Prices for the Partnerships' oil decreased from approximately $16.25 per barrel at December 31, 1997 to approximately $9.50 per barrel at December 31, 1998.
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. Management is unable to predict whether future oil and gas prices will (i) stabilize, (ii) increase, or (iii) decrease.
Significant Customers
The following customers accounted for ten percent or more of the Partnerships' oil and gas sales during the year ended December 31, 1998:
Partnership Purchaser Percentage ----------- ------------------------ ----------
III-A El Paso Energy Marketing Company ("El Paso") 33.9% Valero Industrial Gas L.P. ("Valero") 30.8% Phibro Energy, Inc. ("Phibro") 17.0%
III-B El Paso 26.7% Valero 23.9% Phibro 18.7% Sun Refining & Marketing Company 14.4%
III-C El Paso 55.5%
III-D El Paso 54.9% Eaglwing Trading, Inc. ("Eaglwing") 15.3%
III-E Eaglwing 30.1% El Paso 12.6%
III-F El Paso 28.3%
III-G El Paso 24.5%
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 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 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. 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.
ITEM 2. PROPERTIES
Well Statistics
The following table sets forth the number of productive wells of the Partnerships as of December 31, 1998.
Well Statistics(1) As of December 31, 1998
Number of Gross Wells(2) Number of Net Wells(3) ------------------------------ -------------------------------- P/ship Total Oil Gas N/A(4) Total Oil Gas N/A(4) - -------- ----- ----- --- ------ ------ ------ ----- ------ III-A 192 101 90 1 10.43 2.80 7.60 .03 III-B 141 70 70 1 6.69 3.09 3.59 .01 III-C 170 68 101 1 20.29 11.57 8.71 .01 III-D 205 141 62 2 14.85 8.80 6.01 .04 III-E 260 119 138 3 51.76 25.79 25.66 .31 III-F 495 391 103 1 24.78 13.58 11.16 .04 III-G 2,048 1,657 390 1 16.53 10.21 6.30 .02 - ---------- (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. (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. (4) Wells which have not been designated as oil or gas.
Drilling Activities
During the year ended December 31, 1998, the Partnerships indirectly participated in the developmental drilling activities described below. The Partnerships do not own working interests in any of these wells; therefore, they did not incur any costs associated with the drilling activity:
County/ Revenue P/ship Well Name Parish St. Interest Type Status - ------ --------- -------- --- -------- ---- ------ III-A Lemasters #1-9 Washita OK .0033 Gas Prod. N.H. Clark #14 Webb TX .0075 Gas Prod. J.M. Ruiz #5 Webb TX .0075 Gas Prod. Prevost #6 Webb TX .0075 Gas Prod.
III-B Lemasters #1-9 Washita OK .0022 Gas Prod. N.H. Clark #14 Webb TX .0035 Gas Prod. J.M. Ruiz #5 Webb TX .0035 Gas Prod. Prevost #6 Webb TX .0035 Gas Prod.
III-C Carlisle Trust 34 #1 Harper OK .0004 Gas Unknown Poorbaugh Trust #8-1 Beaver OK .0010 Gas Unknown Follis #1-10 Roger Mills OK .0010 Unk Unknown Pearson #2-28 Pittsburgh OK .0028 Gas Unknown Thornton #2-5 Pittsburgh OK .0009 Gas Unknown N.H. Clark #14 Webb TX .0015 Gas Prod. J.M. Ruiz #5 Webb TX .0015 Gas Prod. Prevost #6 Webb TX .0015 Gas Prod. Canyon Ranch 83-10S Sutton TX .0010 Gas Unknown
III-D Carlisle Trust 34 #1 Harper OK .0001 Gas Unknown Poorbaugh Trust #8-1 Beaver OK .0001 Gas Unknown Follis #1-10 Roger Mills OK .0002 Unk Unknown Pearson #2-28 Pittsburgh OK .0004 Gas Unknown Thornton #2-5 Pittsburgh OK .0001 Gas Unknown Canyon Ranch 83-10S Sutton TX .0001 Gas Unknown
III-E Culbertson B No. 1-ALT Bienville LA .0062 Gas Prod.
III-F Culbertson B No. 1-ALT Bienville LA .0052 Gas Prod.
III-G Culbertson B No. 1-ALT Bienville LA .0026 Gas Prod.
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.
Net Production Data
III-A Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 34,689 40,468 46,923 Gas (Mcf) 741,990 1,031,152 1,268,943 Oil and gas sales: Oil $ 434,592 $ 796,356 $ 975,701 Gas 1,595,205 2,532,278 2,658,303 --------- --------- --------- Total $2,029,797 $3,328,634 $3,634,004 ========= ========= ========= Total direct operating Expenses $ 576,112 $ 719,090 $ 899,073 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 28.4% 21.6% 24.7%
Average sales price: Per barrel of oil $12.53 $19.68 $20.79 Per Mcf of gas 2.15 2.46 2.09
Direct operating expenses per equivalent Bbl of oil $ 3.64 $ 3.39 $ 3.48
Net Production Data
III-B Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 34,221 37,216 37,849 Gas (Mcf) 355,197 518,891 642,152 Oil and gas sales: Oil $ 441,820 $ 735,310 $ 794,186 Gas 759,598 1,236,812 1,319,321 --------- --------- --------- Total $1,201,418 $1,972,122 $2,113,507 ========= ========= ========= Total direct operating Expenses $ 330,107 $ 419,217 $ 497,491 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 27.5% 21.3% 23.5%
Average sales price: Per barrel of oil $12.91 $19.76 $20.98 Per Mcf of gas 2.14 2.38 2.05
Direct operating expenses per equivalent Bbl of oil $ 3.53 $ 3.39 $ 3.43
Net Production Data
III-C Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 22,980 27,069 27,429 Gas (Mcf) 1,156,387 1,124,237 1,351,525 Oil and gas sales: Oil $ 312,050 $ 534,386 $ 567,261 Gas 2,134,955 2,537,465 2,692,354 --------- --------- --------- Total $2,447,005 $3,071,851 $3,259,615 ========= ========= ========= Total direct operating Expenses $ 712,038 $ 749,102 $ 781,115 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 29.1% 24.4% 24.0%
Average sales price: Per barrel of oil $13.58 $19.74 $20.68 Per Mcf of gas 1.85 2.26 1.99
Direct operating expenses per equivalent Bbl of oil $ 3.30 $ 3.49 $ 3.09
Net Production Data
III-D Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 35,908 40,758 41,351 Gas (Mcf) 767,089 708,262 760,593 Oil and gas sales: Oil $ 413,658 $ 778,978 $ 832,109 Gas 1,375,913 1,556,567 1,504,599 --------- --------- --------- Total $1,789,571 $2,335,545 $2,336,708 ========= ========= ========= Total direct operating Expenses $ 718,656 $ 867,060 $ 928,670 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 40.2% 37.1% 39.7%
Average sales price: Per barrel of oil $11.52 $19.11 $20.12 Per Mcf of gas 1.79 2.20 1.98
Direct operating expenses per equivalent Bbl of oil $ 4.39 $ 5.46 $ 5.52
Net Production Data
III-E Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 223,936 235,152 229,226 Gas (Mcf) 1,974,917 2,189,619 2,152,599 Oil and gas sales: Oil $2,542,259 $4,460,740 $4,572,097 Gas 3,858,330 4,581,069 4,458,018 --------- --------- --------- Total $6,400,589 $9,041,809 $9,030,115 ========= ========= ========= Total direct operating Expenses $3,695,174 $4,513,216 $4,418,264 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 57.7% 49.9% 48.9%
Average sales price: Per barrel of oil $11.35 $18.97 $19.95 Per Mcf of gas 1.95 2.09 2.07
Direct operating expenses per equivalent Bbl of oil $ 6.68 $ 7.52 $ 7.51
Net Production Data
III-F Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 54,002 65,787 74,064 Gas (Mcf) 787,609 898,447 924,827 Oil and gas sales: Oil $ 678,439 $1,240,058 $1,494,695 Gas 1,470,754 1,751,392 1,600,043 --------- --------- --------- Total $2,149,193 $2,991,450 $3,094,738 ========= ========= ========= Total direct operating Expenses $1,185,467 $1,332,931 $1,237,607 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 55.2% 44.6% 40.0%
Average sales price: Per barrel of oil $12.56 $18.85 $20.18 Per Mcf of gas 1.87 1.95 1.73
Direct operating expenses per equivalent Bbl of oil $ 6.40 $ 6.18 $ 5.42
Net Production Data
III-G Partnership -----------------
Year Ended December 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- Production: Oil (Bbls) 38,858 47,493 54,083 Gas (Mcf) 419,813 500,966 499,884 Oil and gas sales: Oil $ 487,855 $ 897,536 $1,091,687 Gas 784,720 947,728 870,868 --------- --------- --------- Total $1,272,575 $1,845,264 $1,962,555 ========= ========= ========= Total direct operating Expenses $ 744,443 $ 854,673 $ 804,410 ========= ========= ========= Direct operating expenses as a percentage of oil and gas sales 58.5% 46.3% 41.0%
Average sales price: Per barrel of oil $12.55 $18.90 $20.19 Per Mcf of gas 1.87 1.89 1.74
Direct operating expenses per equivalent Bbl of oil $ 6.84 $ 6.52 $ 5.85
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, 1998. 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 Petroleum Engineers ("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 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, 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 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, 1998. There can be no assurance that the prices used in calculating the net present value of the Partnerships' 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.
Proved Reserves and Net Present Values From Proved Reserves
As of December 31, 1998(1)
III-A Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 4,729,415 Oil and liquids (Bbls) 92,124
Net present value (discounted at 10% per annum) $5,380,825
III-B Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 2,174,036 Oil and liquids (Bbls) 91,163
Net present value (discounted at 10% per annum) $2,667,687
III-C Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 5,768,481 Oil and liquids (Bbls) 134,669
Net present value (discounted at 10% per annum) $5,428,869
III-D Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 2,838,890 Oil and liquids (Bbls) 125,866
Net present value (discounted at 10% per annum) $2,727,210
III-E Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 8,016,475 Oil and liquids (Bbls) 601,310
Net present value (discounted at 10% per annum) $6,856,657
III-F Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 4,726,953 Oil and liquids (Bbls) 231,882
Net present value (discounted at 10% per annum) $4,163,015
III-G Partnership: ----------------- Estimated proved reserves: Gas (Mcf) 2,525,720 Oil and liquids (Bbls) 171,790
Net present value (discounted at 10% per annum) $2,310,504
- ---------- (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.
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 tables set forth certain well and reserve information as of December 31, 1998 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, while the Arkla Basin is located in southern Arkansas and northern Louisiana. The Gulf Coast Basin is located in southern Louisiana and southeast Texas, while the Permian Basin straddles west Texas and southeast New Mexico. Southern Oklahoma contains the Southern Oklahoma Folded Belt Basin. The Green River Basin is located in southern Wyoming and Northwest Colorado.
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.
ITEM 3. LEGAL PROCEEDINGS
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 which would have a material effect on the Partnerships' or the General Partner's financial condition or operations.
ITEM 4.
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 1998.
PART II
ITEM 5.
ITEM 5. MARKET FOR UNITS AND RELATED LIMITED PARTNER MATTERS
As of February 1, 1999, 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 1,379 III-B 138,336 781 III-C 244,536 1,299 III-D 131,008 696 III-E 418,266 2,210 III-F 221,484 1,160 III-G 121,925 615
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 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 -----------------------
1997 1998 1999 ------------------------- ------------------------- ---- 1st 2nd 3rd 4th 1st 2nd 3rd 4th 1st P/ship Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. - ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- III-A $12 $16 $12 $10 $ 8 $16 $15 $14 $14 III-B 12 16 12 10 8 15 14 13 12 III-C 14 19 17 15 13 20 18 16 15 III-D 23 26 24 22 20 26 25 23 21 III-E 31 32 30 28 26 31 29 28 27 III-F 20 22 20 19 17 21 20 19 18 III-G 22 25 23 22 20 23 22 21 20
In addition to this repurchase offer, the Partnerships have been subject to "4.9% tender offers" from several third parties during 1997 and 1998. 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 1997, 1998, and 1999:
Cash Distributions -----------------
------------------------------------------ 1st 2nd 3rd 4th P/ship Qtr.(1) Qtr.(2) Qtr.(1) Qtr.(1) ------ ------ --------- ------- -------
III-A $2.01 $3.24 $4.11 $1.75 III-B 2.49 3.57 4.32 1.97 III-C 2.05 3.26 2.39 1.36 III-D 2.31 3.68 2.42 1.92 III-E 2.55 3.59 2.34 1.81 III-F 1.55 2.98 1.50 1.12 III-G 1.55 3.20 1.82 1.23
1998 1999 ------------------------------------------ ------ 1st 2nd 3rd 4th 1st P/ship Qtr.(1) Qtr.(3) Qtr.(4) Qtr.(5) Qtr. ------ ------ --------- ------- ------- ------
III-A $1.83 2.03 1.11 $1.09 $ .69 III-B 2.15 2.33 1.02 1.32 .73 III-C 2.09 2.62 2.07 1.72 1.29 III-D 2.27 1.85 1.80 1.96 1.28 III-E 1.70 2.16 1.90 1.59 .64 III-F 1.68 1.85 .94 .87 .65 III-G 2.18 1.94 .98 .85 .70
- -------------------
(1) Amount of cash distribution includes proceeds from the sale of certain oil and gas properties. (2) Amount of cash distribution for the III-C and III-D Partnerships includes proceeds from the sale of certain oil and gas properties. (3) Amount of cash distribution for the III-A, III-C, III-D, III-E, III-F, and III-G Partnerships includes proceeds from the sale of certain oil and gas properties. (4) Amount of cash distribution for the III-A, III-C, and III-D Partnerships includes proceeds from the sale of certain oil and gas properties. (5) Amount of cash distribution for the III-B and III-C Partnerships includes proceeds from the sale of certain oil and gas properties.
ITEM 6.
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."
ITEM 7.
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.
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 Partnerships' 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. Gas prices are currently in the lower half of the 10-year average range described above.
Substantially all of the Partnerships' 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 Partnerships' 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 Partnerships 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 a drop in Asian energy demand, oil prices over the past year have reached historically low levels, dropping to as low as approximately $9.25 per barrel. It is not known whether this trend will continue. Prices for the Partnerships' oil decreased from approximately $16.25 per barrel at December 31, 1997 to approximately $9.50 per barrel at December 31, 1998.
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. Management is unable to predict whether future oil and gas prices will (i) stabilize, (ii) increase, or (iii) decrease.
As discussed in the "Results of Operations" section below, volumes of oil and gas sold also significantly affect the Partnerships' revenues. Oil and gas wells generally produce the most oil or gas in the earlier years of their lives and, as production continues, the rate of production naturally declines. At some point, production physically ceases or becomes no longer economic. The Partnerships are not acquiring additional oil and gas properties, and the existing properties are not experiencing significant additional production through drilling or other capital projects. Therefore, volumes of oil and gas produced naturally decline from year to year. While it is difficult for management to predict future production from these properties, it is likely that this general trend of declining production will continue.
Despite this general trend of declining production, several factors can cause the volumes of 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, 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, 1998 as compared to the year ended December 31, 1997, and for the year ended December 31, 1997 as compared to the year ended December 31, 1996.
III-A Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $1,298,837 (39.0%) in 1998 as compared to 1997. Of this decrease, approximately $114,000 and $710,000, respectively, were related to decreases in volumes of oil and gas sold and approximately $248,000 and $227,000, respectively, were related to decreases in the average prices of oil and gas sold. Volumes of oil and gas sold decreased 5,779 barrels and 289,162 Mcf, respectively, in 1998 as compared to 1997. The decrease in the volumes of oil and gas sold resulted primarily from normal declines in production and the sale of several wells during both years. Average oil and gas prices decreased to $12.53 per barrel and $2.15 per Mcf, respectively, in 1998 from $19.68 per barrel and $2.46 per Mcf, respectively, in 1997.
As discussed in "Liquidity and Capital Resources" below, the III-A Partnership sold certain oil and gas properties during 1998 and recognized a $21,281 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-A Partnership recognizing similar gains totaling $148,602.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $142,978 (19.9%) 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 decreases in volume of oil and gas sold. These decreases were partially offset by workover expenses on several
wells during 1998. As a percentage of oil and gas sales, these expenses increased to 28.4% in 1998 from 21.6% in 1997. This percentage increase was primarily due to the decreases in the average prices of oil and gas sold.
Depletion, depreciation, and amortization of oil and gas properties decreased $226,800 (31.3%) 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 increased to 24.6% in 1998 from 21.8% in 1997. This percentage increase resulted primarily from the decreases in the average prices of oil and gas sold.
The III-A Partnership recognized a non-cash charge against earnings of $1,617,006 in the first quarter of 1997. Of this amount, $184,644 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $1,432,362 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-A Partnerships' Partnership Agreement which limit the level of permissible drilling activity. No similar charge was necessary during 1998.
General and administrative expenses remained relatively constant in 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 15.3% in 1998 from 9.4% in 1997, primarily due to the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31, 1998 totaling $25,166,701 or 95.34% of the Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales decreased $305,370 (8.4%) in 1997 as compared to 1996. Of this decrease, approximately $134,000 and $497,000, respectively, were related to decreases in volumes of oil and gas sold and $45,000 was related to a decrease in the average price of oil sold, which decreases were partially offset by an increase of approximately $382,000 related to an increase in the average price of gas sold. Volumes of oil and gas sold decreased 6,455 barrels and 237,791 Mcf, respectively, in 1997 as compared to 1996. The decrease in volumes of oil sold resulted primarily from (i) normal declines in production and (ii) a negative prior period volume adjustment made by a purchaser on one significant well in 1997. The decrease in volumes of gas sold resulted primarily from (i) normal declines in production
and (ii) a positive prior period volume adjustment made by a purchaser on one significant well in 1996. Average oil prices decreased to $19.68 per barrel in 1997 from $20.79 per barrel in 1996. Average gas prices increased to $2.46 per Mcf in 1997 from $2.09 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $179,983 (20.0%) in 1997 as compared to 1996. This decrease resulted primarily from (i) the decreases in volumes of oil and gas sold in 1997 as compared to 1996, (ii) workover expenses incurred on two significant wells during 1996 in order to improve the recovery of reserves, and (iii) 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 21.6% in 1997 from 24.7% in 1996. This percentage decrease was primarily due to the dollar decrease in oil and gas production expenses and the increase in the average price of gas sold in 1997.
Depreciation, depletion, and amortization of oil and gas properties decreased $410,230 (36.1%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below, (ii) the decreases in volumes of oil and gas sold in 1997, and (iii) upward revisions in the estimates of remaining oil and gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 21.8% in 1997 from 31.3% in 1996. This percentage decrease resulted primarily from (i) the dollar decrease in depreciation, depletion, and amortization and (ii) the increases in the average prices of gas sold in 1997.
The III-A Partnership recognized a non-cash charge against earnings of $1,617,006 in the first quarter of 1997. Of this amount, $184,644 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $1,432,362 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-A Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1996.
General and administrative expenses decreased $12,979 (4.0%) in 1997 as compared to 1996. This decrease resulted primarily from the reversal of a prior charge which was recorded in error. As a percentage of oil and gas sales, these expenses remained relatively constant at 9.4% in 1997 and 8.9% in 1996.
III-B Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $770,704 (39.1%) in 1998 as compared to 1997. Of this decrease, approximately $390,000 was related to a decrease in volumes of gas sold and approximately $234,000 and $87,000, respectively, were related to decreases in the average prices of oil and gas sold. Volumes of oil and gas sold decreased 2,995 barrels and 163,694 Mcf, respectively, in 1998 as compared to 1997. The decrease in the volumes of gas sold resulted primarily from normal declines in production and the sale of several wells in both years. Average oil and gas prices decreased to $12.91 per barrel and $2.14 per Mcf, respectively, in 1998 from $19.76 per barrel and $2.38 per Mcf, respectively, in 1997.
As discussed in "Liquidity and Capital Resources" below, the III-B Partnership sold certain oil and gas properties during 1998 and recognized a $33,787 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-B Partnership recognizing similar gains totaling $62,748.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $89,110 (21.3%) in 1998 as compared to 1997. This decrease resulted primarily from a decrease in production taxes associated with the decrease in oil and gas sales and a decrease in lease operating expenses associated with the decreases in volumes of oil and gas sold. These decreases were partially offset by workover expenses on several wells during 1998. As a percentage of oil and gas sales, these expenses increased to 27.5% in 1998 from 21.3% 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 $178,049 (40.0%) in 1998 as compared to 1997. This decrease resulted primarily from the decreases in volumes of oil and gas sold and upward revisions in the estimates of remaining oil and gas reserves at December 31, 1998. As a percentage of oil and gas sales, this expense remained relatively constant at 22.2% in 1998 and 22.6% in 1997.
The III-B Partnership recognized a non-cash charge against earnings of $738,122 in the first quarter of 1997. Of this amount, $77,653 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $660,469 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due
to low oil and gas prices and provisions in the III-B Partnerships' Partnership Agreement which limit the level of permissible drilling activity. No similar charge was necessary during 1998.
General and administrative expenses remained relatively constant in 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 13.6% in 1998 from 8.3% in 1997, primarily due to the decrease in oil and gas sales.
The III-B Partnership achieved payout in the first quarter of 1998. After payout, operations and revenues for the III-B Partnership have been and will be allocated using the after payout percentages included in the III-B Partnership's Partnership Agreement. After payout percentages allocate operating income and expenses 15% to the General Partner and 85% to the Limited Partners. Before payout, operating income and expenses were allocated 5% to the General Partner and 95% to the Limited Partners.
The Limited Partners have received cash distributions through December 31, 1998 totaling $14,662,353 or 105.99% of Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales decreased $141,385 (6.7%) in 1997 as compared to 1996. Of this decrease approximately $13,000 and $293,000, respectively, related to decreases in volumes of oil and gas sold and $46,000 related to a decrease in the average price of oil sold, which decreases were partially offset by an increase of approximately $212,000 related to an increase in the average price of gas sold in 1997. Volumes of oil and gas sold decreased 633 barrels and 123,261 Mcf, respectively, in 1997 as compared to 1996. The decrease in volumes of gas sold resulted primarily from (i) normal declines in production and (ii) a positive prior period volume adjustment made by the purchaser on one significant well in 1996. Average oil prices decreased to $19.76 per barrel in 1997 from $20.98 per barrel in 1996. Average gas prices increased to $2.38 per Mcf in 1997 from $2.05 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $78,274 (15.7%) in 1997 as compared to 1996. This decrease resulted primarily from (i) the decrease in volumes of gas sold in 1997 and (ii) workover expenses incurred on two wells during 1996 in order to improve the recovery of reserves. As a percentage of oil and gas sales, these expenses decreased to 21.3% in 1997 from 23.5% in 1996. This percentage decrease was primarily due to the dollar decrease
in oil and gas production expenses and the increase in the average price of gas sold in 1997.
Depreciation, depletion, and amortization of oil and gas properties decreased $188,404 (29.7%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below, (ii) the decreases in volumes of oil and gas sold in 1997, and (iii) upward revisions in the estimates of remaining oil and gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 22.6% in 1997 from 30.0% in 1996. This percentage decrease resulted primarily from (i) the dollar decrease in depreciation, depletion, and amortization and (ii) the increases in the average prices of gas sold in 1997.
The III-B Partnership recognized a non-cash charge against earnings of $738,122 in the first quarter of 1997. Of this amount, $77,653 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $660,469 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-B Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1996.
General and administrative expenses decreased $7,728 (4.5%) in 1997 as compared to 1996. This decrease resulted primarily from the reversal of a prior charge which was recorded in error. As a percentage of oil and gas sales, these expenses remained relatively constant at 8.3% in 1997 and 8.1% in 1996.
III-C Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $624,846 (20.3%) in 1998 as compared to 1997. Of this decrease, approximately $142,000 and $475,000, respectively, were related to decreases in the average prices of oil and gas sold and approximately $81,000 was related to a decrease in volumes of oil sold. These decreases were partially offset by an increase of approximately $73,000 related to an increase in volumes of gas sold. Volumes of oil sold decreased 4,089 barrels in 1998 as compared to 1997. Volumes of gas sold increased 32,150 Mcf in 1998 as compared to 1997. The decrease in the volumes of oil sold resulted primarily
from normal declines in production and the sale of several wells in both years. Average oil and gas prices decreased to $13.58 per barrel and $1.85 per Mcf, respectively, in 1998 from $19.74 per barrel and $2.26 per Mcf, respectively, in 1997.
As discussed in "Liquidity and Capital Resources" below, the III-C Partnership sold certain oil and gas properties during 1998 and recognized a $459,040 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-C Partnership recognizing similar gains totaling $163,836.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $37,064 (4.9%) in 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 29.1% in 1998 from 24.4% 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 increased $116,636 (18.6%) in 1998 as compared to 1997. This increase resulted primarily from downward revisions in the estimates of remaining oil and gas reserves at December 31, 1998 on two significant wells. As a percentage of oil and gas sales, this expense increased to 30.4% in 1998 from 20.4% in 1997. This percentage increase was primarily due to the dollar increase in depreciation, depletion, and amortization and the decreases in the average prices of oil and gas sold.
The III-C Partnership recognized a non-cash charge against earnings of $1,696,417 in the first quarter of 1997. Of this amount, $234,271 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $1,462,146 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-C Partnerships' partnership agreement which limit the level of permissible drilling activity. No similar charge was necessary during 1998.
General and administrative expenses decreased $5,256 (1.8%) in 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 11.8% in 1998 from 9.5% in 1997, primarily due to the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31, 1998 totaling $17,219,795 or 70.42% of the Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales decreased $187,764 (5.8%) in 1997 as compared to 1996. Of this decrease, approximately $452,000 was related to a decrease in volumes of gas sold and approximately $25,000 was related to a decrease in the average price of oil sold, which decreases were partially offset by an increase of approximately $304,000 related to an increase in the average price of gas sold. Volumes of oil and gas sold decreased by 360 barrels and 227,288 Mcf, respectively, in 1997 as compared to 1996. The decrease in volumes of gas sold resulted primarily from (i) normal declines in production, (ii) a negative prior period volume adjustment made by a purchaser on two significant wells in 1997, and (iii) a positive prior period volume adjustment made by a purchaser on one significant well in 1996. Average oil prices decreased to $19.74 per barrel in 1997 from $20.68 per barrel in 1996. Average gas prices increased to $2.26 per Mcf in 1997 from $1.99 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $32,013 (4.1%) in 1997 as compared to 1996. This decrease resulted primarily from the decrease in volumes of gas sold in 1997, which decrease was partially offset by (i) credits issued on one well during 1996 for prior period rental expenses and (ii) workover expenses incurred on another well during 1997 in order to improve the recovery of reserves. As a percentage of oil and gas sales, these expenses remained relatively constant at 24.4% in 1997 and 24.0% in 1996.
Depreciation, depletion, and amortization of oil and gas properties decreased $303,665 (32.7%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below, (ii) decreases in volumes of oil and gas sold in 1997, and (iii) upward revisions in the estimates of remaining oil and gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 20.4% in 1997 from 28.5% in 1996. This percentage decrease resulted primarily from (i) the dollar decrease in depreciation, depletion, and amortization and (ii) the increases in the average prices of gas sold in 1997.
The III-C Partnership recognized a non-cash charge against earnings of $1,696,417 in the first quarter of 1997. Of this amount, $234,271 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $1,462,146 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination
that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-C Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1996.
General and administrative expenses remained relatively constant in 1997 as compared to 1996. As a percentage of oil and gas sales, these expenses remained relatively constant at 9.5% in 1997 and 9.0% in 1996.
III-D Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $545,974 (23.4%) in 1998 as compared to 1997. Of this decrease, approximately $272,000 and $310,000, respectively, were related to decreases in the average prices of oil and gas sold and approximately $93,000 was related to a decrease in volumes of oil sold. These decreases were partially offset by an increase of approximately $129,000 related to an increase in volumes of gas sold. Volumes of oil sold decreased 4,850 barrels in 1998 as compared to 1997. Volumes of gas sold increased 58,827 Mcf in 1998 as compared to 1997. The decrease in volumes of oil sold resulted primarily from normal declines in production. The increase in volumes of gas sold resulted primarily from the successful recompletion of one well, which increase was partially offset by normal declines in production and the sale of several wells in 1998 and 1997. Average oil and gas prices decreased to $11.52 per barrel and $1.79 per Mcf, respectively, in 1998 from $19.11 per barrel and $2.20 per Mcf, respectively, in 1997.
As discussed in "Liquidity and Capital Resources" below, the III-D Partnership sold certain oil and gas properties during 1998 and recognized a $59,491 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-D Partnership recognizing similar gains totaling $25,425.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $148,404 (17.1%) in 1998 as compared to 1997. This decrease resulted primarily from (i) a decrease in production taxes associated with the decrease in oil and gas sales, (ii) a decrease in lease operating expenses associated with the decreases in volumes of oil and gas sold, and (iii) a decrease in workover expenses on one multi-well unit during 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 40.2% in 1998 from 37.1% in 1997. This 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 increased $197,979 (60.7%) in 1998 as compared to 1997. This increase resulted primarily from significant downward revisions in the estimates of remaining oil and gas reserves at December 31, 1998. As a percentage of oil and gas sales, this expense increased to 29.3% in 1998 from 14.0% in 1997. This percentage increase resulted primarily from the dollar increase in depreciation, depletion, and amortization and the decreases in the average prices of oil and gas sold.
The III-D Partnership recognized a non-cash charge against earnings of $506,636 in the fourth quarter of 1998. This charge was related to the decline in oil and gas prices used to determine recoverability of oil and gas reserves at December 31, 1998. In the first quarter of 1997, a non-cash charge against earnings of $932,243 was also recognized. Of this amount, $485,820 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $446,423 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-D Partnerships' Partnership Agreement which limit the level of permissible drilling activity.
General and administrative expenses decreased $2,958 (1.9%) in 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 8.7% in 1998 from 6.8% in 1997, primarily due to the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31, 1998 totaling $8,529,669 or 65.11% of the Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales remained relatively constant in 1997 as compared to 1996. Decreases of approximately $12,000 and $104,000, respectively, related to decreases in volumes of oil and gas sold and a decrease of approximately $41,000 related to a decrease in the average price of oil sold were substantially offset by an increase of approximately $156,000 related to an increase in the average price of gas sold. Volumes of oil and gas sold decreased 593 barrels and 52,331 Mcf, respectively, in 1997 as compared to 1996. Average oil prices decreased to $19.11 per barrel in 1997 from $20.12 per barrel in 1996. Average gas prices increased to $2.20 per Mcf in 1997 from $1.98 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $61,610 (6.6%) in 1997 as compared to 1996. This decrease resulted primarily from (i) the decrease in volumes of gas sold during 1997 and (ii) a decrease in general repair and maintenance expenses incurred on several wells during 1997 as compared to 1996. As a percentage of oil and gas sales, these expenses decreased to 37.1% in 1997 from 39.7% in 1996. This percentage decrease was primarily due to the dollar decrease in oil and gas production expenses and the increase in the average price of gas sold during 1997.
Depreciation, depletion, and amortization of oil and gas properties decreased $115,418 (26.1%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below, (ii) the decreases in volumes of oil and gas sold in 1997, and (iii) upward revisions in the estimates of remaining oil and gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 14.0% in 1997 from 18.9% in 1996. This percentage decrease resulted primarily from (i) the dollar decrease in depreciation, depletion, and amortization discussed above and (ii) the increases in the average prices of gas sold in 1997.
The III-D Partnership recognized a non-cash charge against earnings of $932,243 in the first quarter of 1997. Of this amount, $485,820 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $446,423 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-D Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1996.
General and administrative expenses remained relatively constant in 1997 as compared to 1996. As a percentage of oil and gas sales, these expenses remained relatively constant at 6.8% in 1997 and 6.8% in 1996.
III-E Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $2,641,220 (29.2%) in 1998 as compared to 1997. Of this decrease, approximately $1,706,000 and $274,000, respectively, were related to decreases in the
average prices of oil and gas sold and approximately $449,000 was related to a decrease in the volumes of gas sold. Volumes of oil and gas sold decreased 11,216 barrels and 214,702 Mcf, respectively, in 1998 as compared to 1997. Average oil and gas prices decreased to $11.35 per barrel and $1.95 per Mcf, respectively, in 1998 from $18.97 per barrel and $2.09 per Mcf, respectively, in 1997.
As discussed in "Liquidity and Capital Resources" below, the III-E Partnership sold certain oil and gas properties during 1998 and recognized a $36,219 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-E Partnership recognizing a $39,835 loss on such sales.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $818,042 (18.1%) in 1998 as compared to 1997. This decrease resulted primarily from (i) a decrease in production taxes associated with the decrease in oil and gas sales, (ii) a decrease in lease operating expenses associated with the decrease in volumes of oil and gas sold, and (iii) a decrease in workover expenses on one significant multi-well unit during 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 57.7% in 1998 from 49.9% 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 increased $785,736 (65.6%) in 1998 as compared to 1997. This increase resulted primarily from significant downward revisions in the estimates of remaining oil and gas reserves at December 31, 1998. As a percentage of oil and gas sales, this expense increased to 31.0% in 1998 from 13.3% in 1997. This percentage increase resulted primarily from the dollar increase in depreciation, depletion, and amortization and the decreases in the average prices of oil and gas sold.
The III-E Partnership recognized a non-cash charge against earnings of $3,503,400 in the fourth quarter of 1998. This charge was related to the decline in oil and gas prices used to determine recoverability of oil and gas reserves at December 31, 1998. In the first quarter of 1997, a non-cash charge against earnings of $2,893,438 was also recognized. Of this amount, $2,042,775 was related to the decline in oil and gas prices used to determine the recoverability of oil and gas reserves at March 31, 1997 and $850,663 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-E Partnership's Partnership Agreement which limit the level of permissible drilling activity.
General and administrative expenses remained relatively constant in 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 7.8% in 1998 from 5.6% in
1997, primarily due to the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31, 1998 totaling $30,221,016 or 72.25% of the Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales remained relatively constant in 1997 as compared to 1996. Increases of approximately $118,000 and $77,000, respectively, related to increases in volumes of oil and gas sold and an increase of approximately $44,000 related to an increase in the average price of gas sold were substantially offset by a decrease of approximately $230,000 related to a decrease in the average price of oil sold. Volumes of oil and gas sold increased 5,926 barrels and 37,020 Mcf, respectively, in 1997 as compared to 1996. Average oil prices decreased to $18.97 per barrel in 1997 from $19.95 per barrel in 1996. Average gas prices increased to $2.09 per Mcf in 1997 from $2.07 in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) increased $94,952 (2.1%) in 1997 as compared to 1996. This increase resulted primarily from the increases in volumes of oil and gas sold in 1997. As a percentage of oil and gas sales, these expenses remained relatively constant at 49.9% in 1997 and 48.9% in 1996.
Depreciation, depletion, and amortization of oil and gas properties decreased $539,246 (31.0%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below and (ii) upward revisions in the estimates of remaining gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 13.3% in 1997 from 19.2% in 1996. This percentage decrease resulted primarily from the dollar decrease in depreciation, depletion, and amortization discussed above.
The III-E Partnership recognized a non-cash charge against earnings of $2,893,438 in the first quarter of 1997. Of this amount, $2,042,775 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $850,663 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-E
Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1996.
General and administrative expenses remained relatively constant in 1997 as compared to 1996. As a percentage of oil and gas sales, these expenses remained relatively constant at 5.6% in 1997 and 5.6% in 1996.
III-F Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $842,257 (28.2%) for 1998 as compared to 1997. Of this decrease, approximately $222,000 and $216,000, respectively, were related to decreases in volumes of oil and gas sold and approximately $339,000 and $65,000, respectively, were related to decreases in the average prices of oil and gas sold. Volumes of oil and gas sold decreased 11,785 barrels and 110,838 Mcf, respectively, for 1998 as compared to 1997. The decrease in volumes of oil sold resulted primarily from normal declines in production and the sale of several wells during 1998 and 1997. The decrease in volumes of gas sold resulted primarily from (i) normal declines in production, (ii) the shutting-in of two significant wells during a portion of 1998 in order to perform a workover on one well and repairs on the other well, and (iii) the sale of several wells during 1998 and 1997. Average oil and gas prices decreased to $12.56 per barrel and $1.87 per Mcf, respectively, for 1998 from $18.85 per barrel and $1.95 per Mcf, respectively, for 1997.
As discussed in "Liquidity and Capital Resources" below, the III-F Partnership sold certain oil and gas properties during 1998 and recognized a $22,073 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-F Partnership recognizing losses totaling $14,411 on such sales.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $147,464 (11.1%) for 1998 as compared to 1997. This decrease resulted primarily from (i) workover expenses incurred on several wells during 1997 in order to improve the recovery of reserves and (ii) the sale of one significant well during 1997. These decreases were partially offset by workover expenses and repair and maintenance expenses incurred during 1998 on several wells. As a percentage of oil and gas sales, these expenses increased to 55.2% for 1998 from 44.6% for 1997. This percentage increase was primarily due to (i) the decreases in the average prices of oil and gas sold during 1998 and (ii) the workover expenses and repair and maintenance expenses incurred during 1998.
Depreciation, depletion, and amortization of oil and gas properties decreased $34,359 (4.5%) for 1998 as compared to 1997. This decrease was primarily due to the decreases in volumes of oil and gas sold, which decrease was partially offset by downward revisions in the estimates of remaining oil reserves at December 31, 1998 on two significant wells. As a percentage of oil and gas sales, this expense increased to 33.6% for 1998 from 25.3% for 1997. This percentage increase resulted primarily from the decreases in the average prices of oil and gas sold.
The III-F Partnership recognized a non-cash charge against earnings of $2,884,405 in the first quarter of 1997. Of this amount, $2,078,019 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $806,386 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-F Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1998.
General and administrative expenses decreased $5,087 (1.9%) for 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 12.1% for 1998 from 8.9% for 1997, primarily due to the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31, 1998 totaling $11,129,904 or 50.25% of Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales decreased $103,288 (3.3%) in 1997 as compared to 1996. Of this decrease, approximately $167,000 and $46,000, respectively, related to decreases in volumes of oil and gas sold and approximately $87,000 related to a decrease in the average price of oil sold, which decreases were partially offset by an increase of approximately $198,000 related to an increase in the average price of gas sold. Volumes of oil and gas sold decreased by 8,277 barrels and 26,380 Mcf, respectively, in 1997 as compared to 1996. The decrease in volumes of oil sold resulted primarily from (i) normal declines in production and (ii) the sale of two significant wells in mid-1996. Average oil prices decreased to $18.85 per barrel in 1997 from $20.18 per barrel in 1996. Average gas prices increased to $1.95 per Mcf in 1997 from $1.73 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) increased $95,324 (7.7%) in 1997 as compared to 1996. This increase resulted primarily from (i) workover expenses incurred on three wells during 1997 in order to improve the recovery of reserves and (ii) credits issued on one well during 1996 for prior period rental expenses, which increases were partially offset by the decreases in volumes of oil and gas sold during 1997. As a percentage of oil and gas sales, these expenses increased to 44.6% in 1997 from 40.0% in 1996. This percentage increase was primarily due to the dollar increase in oil and gas production expenses discussed above and the decrease in the average price of oil sold during 1997.
Depreciation, depletion, and amortization of oil and gas properties decreased $374,649 (33.1%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below, (ii) the decreases in volumes of oil and gas sold in 1997, and (iii) upward revisions in the estimates of remaining gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 25.3% in 1997 from 36.5% in 1996. This percentage decrease resulted primarily from (i) the dollar decrease in depreciation, depletion, and amortization discussed above and (ii) the increases in the average prices of gas sold in 1997.
The III-F Partnership recognized a non-cash charge against earnings of $2,884,405 in the first quarter of 1997. Of this amount, $2,078,019 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $806,386 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-F Partnership's Partnership Agreement which limit the level of permissible drilling activity. No similar charges were necessary in 1996.
General and administrative expenses remained relatively constant in 1997 as compared to 1996. As a percentage of oil and gas sales, these expenses remained relatively constant at 8.9% in 1997 and 8.6% in 1996.
III-G Partnership -----------------
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 -------------------------------------
Total oil and gas sales decreased $572,689 (31.0%) for 1998 as compared to 1997. Of this decrease, approximately $163,000 and $154,000, respectively, were related to decreases in volumes of oil and gas sold and approximately $246,000 was related to a decrease in the average price of oil sold. Volumes of oil and gas sold decreased 8,635 barrels and 81,153 Mcf, respectively, for 1998 as compared to 1997. The decrease in volumes of oil sold resulted primarily from normal declines in production and the sale of several wells during 1998 and 1997. The decrease in volumes of gas sold resulted primarily from (i) normal declines in production, (ii) the shutting-in of two significant wells during a portion of 1998 in order to perform a workover on one well and repairs on the other well, and (iii) the sale of several wells during 1998 and 1997. Average oil and gas prices decreased to $12.55 per barrel and $1.87 per Mcf, respectively, for 1998 from $18.90 per barrel and $1.89 per Mcf, respectively, for 1997.
As discussed in "Liquidity and Capital Resources" below, the III-G Partnership sold certain oil and gas properties during 1998 and recognized a $19,340 gain on such sales. Sales of oil and gas properties during 1997 resulted in the III-G Partnership recognizing similar gains totaling $4,685.
Oil and gas production expenses (including lease operating expenses and production taxes) decreased $110,230 (12.9%) for 1998 as compared to 1997. This decrease resulted primarily from (i) workover expenses incurred on several wells during 1997 in order to improve the recovery of reserves and (ii) the sale of one significant well during 1997. These decreases were partially offset by workover expenses and repair and maintenance expenses incurred during 1998 on several wells. As a percentage of oil and gas sales, these expenses increased to 58.5% for 1998 from 46.3% for 1997. This percentage increase was primarily due to (i) the decrease in the average price of oil sold and (ii) the workover expenses and repair and maintenance expenses incurred during 1998.
Depreciation, depletion, and amortization of oil and gas properties decreased $25,309 (5.9%) for 1998 as compared to 1997. This decrease was primarily due to the decreases in volumes of oil and gas sold, which decrease was partially offset by downward revisions in the estimates of remaining oil reserves at December 31, 1998 on two significant wells. As a percentage of oil and gas sales, this expense increased to 31.5% for 1998 from 23.1% for 1997. This percentage increase resulted primarily from the decrease in the average price of oil sold.
The III-G Partnership recognized a non-cash charge against earnings of $310,413 in the fourth quarter of 1998. This charge was related to the decline in oil and gas prices used to determine the recoverability of oil and gas reserves at December 31, 1998. The III-G Partnership also recognized non-cash charges against earnings totaling $1,551,780 in 1997. Of this amount, $1,449,404 was recognized in the first quarter of 1997 and $102,376 was recognized in the fourth quarter of 1997. Of the first quarter charge in 1997, $1,010,738 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $438,666 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-G Partnership's Partnership Agreement which limit the level of permissible drilling activity. The charge in the fourth quarter of 1997 was related to the decline in oil prices used to determine the recoverability of proved oil reserves at December 31, 1997.
General and administrative expenses decreased $2,876 (2.0%) for 1998 as compared to 1997. As a percentage of oil and gas sales, these expenses increased to 11.3% for 1998 from 7.9% for 1997, primarily due to the decrease in oil and gas sales.
The Limited Partners have received cash distributions through December 31, 1998 totaling $5,847,287 or 47.96% of Limited Partners' capital contributions.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 -------------------------------------
Total oil and gas sales decreased $117,291 (6.0%) in 1997 as compared to 1996. Of this decrease, approximately $133,000 related to a decrease in volumes of oil sold and approximately $61,000 related to a decrease in the average price of oil sold, which decreases were partially offset by an increase of approximately $75,000 related to an increase in the average price of gas sold. Volumes of oil sold decreased 6,590 barrels in 1997 as compared to 1996. Volumes of gas sold increased 1,082 Mcf in 1997 as compared to 1996. The decrease in volumes of oil sold resulted primarily from (i) a normal decline in production and (ii) the sale of several wells in 1996. Average oil prices decreased to $18.90 per barrel in 1997 from $20.19 per barrel in 1996. Average gas prices increased to $1.89 per Mcf in 1997 from $1.74 per Mcf in 1996.
Oil and gas production expenses (including lease operating expenses and production taxes) increased $50,263 (6.2%) in 1997 as compared to 1996. This increase resulted primarily from (i)
workover expenses incurred on three wells during 1997 in order to improve the recovery of reserves and (ii) an increase in general repair and maintenance expenses incurred on one significant well during 1997 as compared to 1996, which increase was partially offset by the decrease in volumes of oil sold during 1997. As a percentage of oil and gas sales, these expenses increased to 46.3% in 1997 from 41.0% in 1996. This percentage increase was primarily due to the dollar increase in oil and gas production expenses discussed above and the decrease in the average price of oil sold during 1997.
Depreciation, depletion, and amortization of oil and gas properties decreased $227,810 (34.9%) in 1997 as compared to 1996. This decrease resulted primarily from (i) a reduction in the depletable base of oil and gas properties due to the impairment provision recorded in the first quarter of 1997 as discussed below, (ii) the decreases in volumes of oil sold in 1997, and (iii) upward revisions in the estimates of remaining gas reserves at December 31, 1997. As a percentage of oil and gas sales, this expense decreased to 23.1% in 1997 from 33.3% in 1996. This percentage decrease resulted primarily from (i) the dollar decrease in depreciation, depletion, and amortization discussed above and (ii) the increases in the average prices of gas sold in 1997.
The III-G Partnership recognized a non-cash charge against earnings of $1,449,404 in the first quarter of 1997 and $102,376 in the fourth quarter of 1997. Of the first quarter charge, $1,010,738 was related to the decline in oil and gas prices used to determine the recoverability of proved oil and gas reserves at March 31, 1997 and $438,666 was related to the writing-off of unproved properties. These unproved properties were written off based on the General Partner's determination that it was unlikely that such properties would be developed due to low oil and gas prices and provisions in the III-G Partnership's Partnership Agreement which limit the level of permissible drilling activity. The fourth quarter charge of $102,376 was primarily related to the decline in oil prices used to determine the recoverability of proved oil and gas reserves at December 31, 1997. No similar charges were necessary in 1996.
General and administrative expenses remained relatively constant in 1997 as compared to 1996. As a percentage of oil and gas sales, these expenses remained relatively constant at 7.9% in 1997 and 7.5% in 1996.
Average Sale Prices, Production Volumes, and Average Production Costs
The following tables are comparisons of annual average oil and gas sales prices, production volumes, and average production costs (lease operating expenses and production taxes) per
equivalent unit (one barrel or 6 Mcf of gas) for 1998, 1997, and 1996. These factors comprise the change in net oil and gas operations discussed in the "Results of Operations" section above.
1998 Compared to 1997 ---------------------
Average Sales Prices - ---------------------------------------------------------------------------- P/ship 1998 1997 % Change - ------ ------------------- ----------------- ------------- Oil Gas Oil Gas ($/Bbl) ($/Mcf) ($/Bbl) ($/Mcf) Oil Gas ------- ------- ------- ------- ----- ---- III-A $12.53 $2.15 $19.68 $2.46 (36%) (13%) III-B 12.91 2.14 19.76 2.38 (35%) (10%) III-C 13.58 1.85 19.74 2.26 (31%) (18%) III-D 11.52 1.79 19.11 2.20 (40%) (19%) III-E 11.35 1.95 18.97 2.09 (40%) ( 7%) III-F 12.56 1.87 18.85 1.95 (33%) ( 4%) III-G 12.55 1.87 18.90 1.89 (34%) ( 1%)
Production Volumes - ---------------------------------------------------------------------------- P/ship 1998 1997 % Change - ------ --------------------- ------------------- ------------- Oil Gas Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) ------- --------- ------- --------- ------ ----- III-A 34,689 741,990 40,468 1,031,152 (14%) (28%) III-B 34,221 355,197 37,216 518,891 ( 8%) (32%) III-C 22,980 1,156,387 27,069 1,124,237 (15%) 3% III-D 35,908 767,089 40,758 708,262 (12%) 8% III-E 223,936 1,974,917 235,152 2,189,619 ( 5%) (10%) III-F 54,002 787,609 65,787 898,447 (18%) (12%) III-G 38,858 419,813 47,493 500,966 (18%) (16%)
Average Production Costs per Equivalent Barrel of Oil ----------------------------------- P/ship 1998 1997 % Change ------ ----- ----- -------- III-A $3.64 $3.39 7% III-B 3.53 3.39 4% III-C 3.30 3.49 ( 5%) III-D 4.39 5.46 (20%) III-E 6.68 7.52 (11%) III-F 6.40 6.18 4% III-G 6.84 6.52 5%
1997 Compared to 1996 ---------------------
Average Sales Prices - ---------------------------------------------------------------------------- P/ship 1997 1996 % Change - ------ ------------------- ----------------- ------------- Oil Gas Oil Gas ($/Bbl) ($/Mcf) ($/Bbl) ($/Mcf) Oil Gas ------- ------- ------- ------- ----- ---- III-A $19.68 $2.46 $20.79 $2.09 (5%) 18% III-B 19.76 2.38 20.98 2.05 (6%) 16% III-C 19.74 2.26 20.68 1.99 (5%) 14% III-D 19.11 2.20 20.12 1.98 (5%) 11% III-E 18.97 2.09 19.95 2.07 (5%) 1% III-F 18.85 1.95 20.18 1.73 (7%) 13% III-G 18.90 1.89 20.19 1.74 (6%) 9%
Production Volumes - ---------------------------------------------------------------------------- P/ship 1997 1996 % Change - ------ --------------------- ------------------- ------------- Oil Gas Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) ------- --------- ------- --------- ------ ----- III-A 40,468 1,031,152 46,923 1,268,943 (14%) (19%) III-B 37,216 518,891 37,849 642,152 ( 2%) (19%) III-C 27,069 1,124,237 27,429 1,351,525 ( 1%) (17%) III-D 40,758 708,262 41,351 760,593 ( 1%) ( 7%) III-E 235,152 2,189,619 229,226 2,152,599 3% 2% III-F 65,787 898,447 74,064 924,827 (11%) ( 3%) III-G 47,493 500,966 54,083 499,884 (12%) -%
Average Production Costs per Equivalent Barrel of Oil ----------------------------------- P/ship 1997 1996 % Change ------ ----- ----- -------- III-A $3.39 $3.48 ( 3%) III-B 3.39 3.43 ( 1%) III-C 3.49 3.09 13% III-D 5.46 5.52 ( 1%) III-E 7.52 7.51 -% III-F 6.18 5.42 14% III-G 6.52 5.85 11%
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 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 Partnerships' proved reserve quantities at December 31, 1998 would have the following remaining lives:
Partnership Gas-Years Oil-Years ----------- --------- ---------
III-A 6.4 2.7 III-B 6.1 2.7 III-C 5.0 5.9 III-D 3.7 3.5 III-E 4.1 2.7 III-F 6.0 4.3 III-G 6.0 4.4
The Partnerships' available capital from the Limited Partners' subscriptions has been spent on oil and gas properties and there should be no further material capital resource commitments in the future. Occasional expenditures by the Partnerships for new wells or well completions or workovers, however, may reduce or eliminate cash available for a particular quarterly cash distribution. The Partnerships have no debt commitments. Cash for operational purposes will be provided by current oil and gas production.
The Partnerships sold certain oil and gas properties during 1997 and 1998. The sale of the Partnerships' properties was made by the General Partner after giving due consideration to both the offer price and the General Partner's estimate of the property's remaining proved reserves and future operating costs. Net proceeds from the sale of such properties were included in the calculation of the Partnerships' cash distributions for the quarter immediately following the Partnerships' receipt of the proceeds. The amount of such proceeds from the sale of oil and gas properties during 1998 and 1997 were as follows:
Partnership 1998 1997 ----------- ---------- -------- III-A $ 25,815 $572,237 III-B 35,047 278,513 III-C 501,935 231,006 III-D 67,181 26,912 III-E 77,860 38,925 III-F 56,560 83,156 III-G 33,830 65,190
The General Partner believes that the sale of these properties will be beneficial to the Partnerships in the long-term since the properties sold generally had a higher ratio of future operating expenses as compared to reserves than the properties not sold.
There can be no assurance as to the amount of the Partnerships' future cash distributions. The Partnerships' ability to make cash distributions depends primarily upon the level of available cash flow generated by the Partnerships' operating activities, which will be affected (either positively or negatively) by many factors beyond the control of the Partnerships, 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 Partnerships are not replacing production through acquisitions of producing properties and drilling. The Partnerships' quantity of proved reserves has been reduced by the sale of oil and gas properties as described above; therefore, it is possible that the Partnerships' future cash distributions will decline as a result of a reduction of the Partnerships' reserve base.
The Partnerships will terminate on the following dates in accordance with the Partnership Agreements:
Partnership Termination Date ----------- -----------------
III-A November 28, 1999 III-B January 24, 2000 III-C February 28, 2000 III-D September 5, 2000 III-E December 26, 2000 III-F March 7, 2001 III-G September 20, 2001
However, the Partnership Agreements provide that the General Partner may extend the term of each Partnership for five periods of two years each. As of the date of this Annual Report, the General Partner intends to extend the term of the III-A, III-B, and III-C Partnerships for the first two-year extension period, but has not determined whether it intends to (i) further extend the term of such Partnerships or (ii) extend the term of any other Partnership.
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 Partnerships 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
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. This interdependence also exists among the Partnerships, 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, the General Partner does not believe that these risks will be material to the Partnerships' operations.
The Partnerships' business is producing oil and gas. The day-to-day production of the Partnerships' oil and gas is not dependent on computers or equipment with imbedded chips. As further discussed below, management anticipates that the Partnerships' daily business activities will not be materially affected by Y2K.
The Partnerships 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 February 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 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 1st 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 March 31, 1999 to complete this process. The costs of all such risk assessments and remediation are not expected to be material to the Partnerships.
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 Partnerships 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 equipment is very minor with respect to the entire Samson group, and, in fact, the Partnerships' 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 March 31, 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 Partnerships. 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 Partnerships 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, 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 Partnerships' 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, the General Partner 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 Partnerships' 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Partnerships do not hold any market risk sensitive instruments.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary data are indexed in Item 14 hereof.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
The Partnerships have no directors or executive officers. The following individuals are directors and executive officers of the General Partner. The business address of such director and executive officers is Two West Second Street, Tulsa, Oklahoma 74103.
Name Age Position with Geodyne ---------------- --- -------------------------------- Dennis R. Neill 46 President and Director
Judy K. Fox 47 Secretary
The director will hold office until the next annual meeting of shareholders of Geodyne 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 Geodyne on March 3, 1993, and was named President of Geodyne and its subsidiaries on June 30, 1996. Prior to joining Samson, he was associated with a Tulsa law firm, Conner and Winters, where 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, Dyco Petroleum Corporation, Berry Gas Company, Circle L Drilling Company, Snyder Exploration Company, and Compression, Inc.
Judy K. Fox joined Samson in 1990 and was named Secretary of Geodyne and its subsidiaries 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., Dyco Petroleum Corporation, Samson Hydrocarbons Company, Snyder Exploration Company, and Samson Properties Incorporated.
Section 16(a) Beneficial Ownership Reporting Compliance
To the best knowledge of the Partnerships and the General Partner, there were no officers, directors, or ten percent owners who were delinquent filers during 1998 of reports required under Section 16 of the Securities Exchange Act of 1934.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The General Partner and its affiliates are reimbursed for actual general and administrative costs and operating costs incurred and attributable to the conduct of the business affairs and operations of the Partnerships, computed on a cost basis, determined in accordance with generally accepted accounting principles. Such reimbursed costs and expenses allocated to the Partnerships include office rent, secretarial, employee compensation and benefits, travel and communication costs, fees for professional services, and other items generally classified as general or administrative expense. The amount of general and administrative expense allocated to the General Partner and its affiliates which was charged to each Partnership during 1998, 1997, and 1996 is set forth in the table below. Although the actual costs incurred by the General Partner and its affiliates have fluctuated during the three years presented, the amounts charged to the Partnerships have not fluctuated due to expense limitations imposed by the Partnership Agreements.
Partnership 1998 1997 1996 ----------- -------- -------- --------
III-A $277,872 $277,872 $277,872 III-B 145,620 145,620 145,620 III-C 257,412 257,412 257,412 III-D 137,904 137,904 137,904 III-E 440,280 440,280 440,280 III-F 233,136 233,136 233,136 III-G 128,340 128,340 128,340
None of the officers or directors of the General Partner receive compensation directly from the Partnerships. The Partnerships reimburse the General Partner or its affiliates for that portion of such officers' and directors' salaries and expenses attributable to time devoted by such individuals to the Partnerships' activities. The following tables indicate the approximate amount of general and administrative expense reimbursement attributable to the salaries of the directors, officers, and employees of the General Partner and its affiliates during 1998, 1997, and 1996:
Affiliates of the Partnerships serve as operator of some of the Partnerships' wells. The 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. Such compensation may occur both prior and subsequent to the commencement of commercial marketing of production of oil or gas. The dollar amount of such compensation paid by the Partnerships to the affiliates is impossible to quantify as of the date of this Annual Report.
Samson maintains necessary inventories of new and used field equipment. Samson may have provided some of this equipment for wells in which the Partnerships 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 billed the Partnerships for a portion of such costs based upon the Partnerships' interest in the well.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table provides information as to the beneficial ownership of the Units as of February 1, 1999 (i) each beneficial owner of more than five percent of the issued and outstanding Units, (ii) the directors and officers of the General Partner, and (iii) the General Partner and its affiliates. 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) - ------------------------------------ ------------------
III-A Partnership: - ----------------- Samson Resources Company 31,866 (12.1%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 31,866 (12.1%)
III-B Partnership: - ----------------- Samson Resources Company 18,856 (13.6%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 18,856 (13.6%)
III-C Partnership: - ----------------- Samson Resources Company 34,335 (14.0%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 34,335 (14.0%)
III-D Partnership: - ----------------- Samson Resources Company 21,975 (16.8%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 21,975 (16.8%)
III-E Partnership: - ----------------- Samson Resources Company 95,390 (22.8%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 95,390 (22.8%)
III-F Partnership: - ----------------- Samson Resources Company 37,905 (17.1%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 37,905 (17.1%)
III-G Partnership: - ----------------- Samson Resources Company 18,242 (15.0%)
All affiliates, directors, and officers of the General Partner as a group and the General Partner (4 persons) 18,242 (15.0%)
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The General Partner and certain of its affiliates engage in oil and gas activities independently of the Partnerships 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 Partnerships and the General Partner also create potential conflicts of interest. An affiliate of the Partnerships owns some of the Partnerships' Units and therefore has an identity of interest with other Limited Partners with respect to the operations of the Partnerships.
In order to attempt to assure limited liability for Limited Partners as well as an orderly conduct of business, management of the Partnerships is exercised solely by the General Partner. The Partnership Agreements grant the General Partner broad discretionary authority with respect to the Partnerships' 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 Partnerships involves circumstances where the General Partner has conflicts of interest and where it must allocate costs and expenses, or opportunities, among the Partnerships and other competing interests.
The General Partner does not devote all of its time, efforts, and personnel exclusively to the Partnerships. Furthermore, the Partnerships do not have any employees, but instead rely on the personnel of Samson. The Partnerships thus compete with Samson (including other oil and gas partnerships) for the time and resources of such personnel. Samson devotes such time and personnel to the management of the Partnerships as are indicated by the circumstances and as are consistent with the General Partner's fiduciary duties.
Affiliates of the Partnerships are solely responsible for the negotiation, administration, and enforcement of oil and gas sales agreements covering the Partnerships' leasehold interests. Because affiliates of the Partnerships who provide services to the Partnerships 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 the Partnerships would take if they were to administer their own contracts without involvement with other members of Samson. On the other hand, management believes that the Partnerships' negotiating strength and contractual positions have been enhanced by virtue of their affiliation with Samson.
PART I
PART IV
ITEM 14.
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
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 Geodyne Energy Income Limited Partnership III-G
as of December 31, 1998 and 1997 and for each of the three years in the period ended December 31, 1998 are filed as part of this report:
Report of Independent Accountants Balance Sheets Statements of Operations Statements of Changes in Partners' Capital (Deficit) Statements of Cash Flows Notes to Financial Statements
(2) Financial Statement Schedules:
None.
(3) Exhibits:
4.1 The Certificate and Agreements of Limited Partnership for the following Partnerships have been previously filed with the Securities and Exchange Commission as Exhibit 2.1 to Form 8-A filed by each Partnership on the dates shown below and are hereby incorporated by reference.
Partnership Filing Date File No. ----------- ----------- --------
III-A February 20, 1990 0-18302 III-B March 30, 1990 0-18636 III-C March 30, 1990 0-18634 III-D November 14, 1990 0-18936 III-E January 22, 1991 0-19010 III-F March 25, 1991 0-19102 III-G September 30, 1991 0-19563
4.2 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-A, filed as Exhibit 4.1 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.3 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-B, filed as Exhibit 4.2 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.4 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-C, filed as Exhibit 4.3 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.5 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-D, filed as Exhibit 4.4 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.6 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-E, filed as Exhibit 4.5 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.7 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-F, filed as Exhibit 4.6 to
Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.8 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-G, filed as Exhibit 4.7 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.9 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-A, filed as Exhibit 4.10 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.10 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-B, filed as Exhibit 4.11 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.11 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-C, filed as Exhibit 4.12 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.12 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-D, filed as Exhibit 4.13 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.13 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-E, filed as Exhibit 4.14 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.14 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-F, filed as Exhibit 4.15 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.15 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-G, filed as Exhibit 4.16 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
* 23.1 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-A.
* 23.2 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-B.
* 23.3 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-C.
* 23.4 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-D.
* 23.5 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-E.
* 23.6 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-F.
* 23.7 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-G.
* 27.1 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-A'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 Geodyne Energy Income Limited Partnership
III-B's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
* 27.3 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-C's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
* 27.4 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-D's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
* 27.5 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-E's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
* 27.6 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-F's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
* 27.7 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-G'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.
(b) Reports on Form 8-K filed during the fourth quarter of 1998:
None.
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.
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 GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-G
By: GEODYNE RESOURCES, INC. General Partner
February 23, 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 February 23, 1999 ------------------- Director (Principal Dennis R. Neill Executive Officer)
/s/Patrick M. Hall (Principal February 23, 1999 ------------------- Financial and Patrick M. Hall Accounting Officer)
/s/Judy K. Fox Secretary February 23, 1999 ------------------- Judy K. Fox
Item 8: Financial Statements and Supplementary Data
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-A
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-A, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-A Balance Sheets December 31, 1998 and 1997
ASSETS ------ 1998 1997 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents $ 212,695 $ 522,371 Accounts receivable: Oil and gas sales 282,108 524,541 Other - 308 --------- --------- Total current assets $ 494,803 $1,047,220
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 2,222,673 2,669,949
DEFERRED CHARGE 266,532 199,722 --------- --------- $2,984,008 $3,916,891 ========= =========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 62,011 $ 39,622 Gas imbalance payable 30,903 38,418 --------- ---------
Total current liabilities $ 92,914 $ 78,040
ACCRUED LIABILITY $ 76,845 $ 51,905
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 197,325) ($ 198,271) Limited Partners, issued and outstanding, 263,976 Units 3,011,574 3,985,217 --------- --------- Total Partners' capital $2,814,249 $3,786,946 --------- --------- $2,984,008 $3,916,891 ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-A Statements of Operations For the Years Ended December 31, 1998, 1997, and 1996
1998 1997 1996 ----------- ----------- ----------- REVENUES: Oil and gas sales $2,029,797 $3,328,634 $3,634,004 Interest income 16,726 27,613 23,840 Gain (loss) on sale of oil and gas properties 21,281 148,602 ( 84,561) --------- --------- --------- $2,067,804 $3,504,849 $3,573,283
COSTS AND EXPENSES: Lease operating $ 412,509 $ 463,734 $ 644,998 Production tax 163,603 255,356 254,075 Depreciation, deple- tion, and amorti- zation of oil and gas properties 498,715 725,515 1,135,745 Impairment provision - 1,617,006 - General and administrative 311,430 311,253 324,232 --------- --------- --------- $1,386,257 $3,372,864 $2,359,050 --------- --------- ---------
NET INCOME $ 681,547 $ 131,985 $1,214,233 ========= ========= =========
GENERAL PARTNER - NET INCOME $ 53,190 $ 98,919 $ 104,949 ========= ========= =========
LIMITED PARTNERS - NET INCOME $ 628,357 $ 33,066 $1,109,284 ========= ========= ========= NET INCOME per Unit $ 2.38 $ .13 $ 4.20 ========= ========= ========= UNITS OUTSTANDING 263,976 263,976 263,976 ========= ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-A Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------- ----------- -------------
Balance, Dec. 31, 1995 $ 8,275,867 ($143,923) $8,131,944 Net income 1,109,284 104,949 1,214,233 Cash distributions ( 2,499,000) ( 159,937) ( 2,658,937) ---------- ------- ---------
Balance, Dec. 31, 1996 $ 6,886,151 ($198,911) $6,687,240 Net income 33,066 98,919 131,985 Cash distributions ( 2,934,000) ( 98,279) ( 3,032,279) ---------- ------- ---------
Balance, Dec. 31, 1997 $ 3,985,217 ($198,271) $3,786,946 Net income 628,357 53,190 681,547 Cash distributions ( 1,602,000) ( 52,244) ( 1,654,244) ---------- ------- ---------
Balance, Dec. 31, 1998 $ 3,011,574 ($197,325) $2,814,249 ========== ======= =========
The accompanying notes are an integral part of these financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-B
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-B, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-B Balance Sheets December 31, 1998 and 1997
ASSETS ------ 1998 1997 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents $ 117,355 $ 305,288 Accounts receivable: Oil and gas sales 164,818 307,724 Other - 130 --------- --------- Total current assets $ 282,173 $ 613,142
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 1,242,380 1,499,148
DEFERRED CHARGE 193,310 136,296 --------- --------- $1,717,863 $2,248,586 ========= =========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 21,658 $ 19,432 Gas imbalance payable 18,422 6,676 --------- ---------
Total current liabilities $ 40,080 $ 26,108
ACCRUED LIABILITY $ 41,436 $ 28,494
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 85,016) ($ 97,840) Limited Partners, issued and outstanding, 138,336 Units 1,721,363 2,291,824 --------- --------- Total Partners' capital $1,636,347 $2,193,984 --------- ---------
$1,717,863 $2,248,586 ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-B Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------ ---------- -------------
Balance, Dec. 31, 1995 $4,466,796 ($ 66,996) $4,399,800 Net income 712,800 63,531 776,331 Cash distributions ( 1,403,000) ( 93,627) ( 1,496,627) --------- ------- ---------
Balance, Dec. 31, 1996 $3,776,596 ($ 97,092) $3,679,504 Net income 223,228 60,762 283,990 Cash distributions ( 1,708,000) ( 61,510) ( 1,769,510) --------- ------- ---------
Balance, Dec. 31, 1997 $2,291,824 ($ 97,840) $2,193,984 Net income 374,539 108,544 483,083 Cash distributions ( 945,000) ( 95,720) ( 1,040,720) --------- ------- ---------
Balance, Dec. 31, 1998 $1,721,363 ($ 85,016) $1,636,347 ========= ======= =========
The accompanying notes are an integral part of these financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-C
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-C, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-C Balance Sheets December 31, 1998 and 1997
ASSETS ------
1998 1997 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents $ 340,720 $ 540,911 Accounts receivable: Oil and gas sales 380,975 497,683 Other - 54 --------- --------- Total current assets $ 721,695 $1,038,648
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 2,779,845 3,442,631
DEFERRED CHARGE 70,849 86,649 --------- --------- $3,572,389 $4,567,928 ========= =========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 42,712 $ 53,049 Gas imbalance payable 25,479 30,493 --------- ---------
Total current liabilities $ 68,191 $ 83,542
ACCRUED LIABILITY $ 151,671 $ 142,828
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 179,285) ($ 171,438) Limited Partners, issued and outstanding, 244,536 Units 3,531,812 4,512,996 --------- --------- Total Partners' capital $3,352,527 $4,341,558 --------- --------- $3,572,389 $4,567,928 ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-C Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------- ---------- -------------
Balance, Dec. 31, 1995 $7,451,351 ($125,913) $7,325,438 Net income 1,247,672 103,933 1,351,605 Cash distributions ( 1,775,000) ( 121,761) ( 1,896,761) --------- ------- ---------
Balance, Dec. 31, 1996 $6,924,023 ($143,741) $6,780,282 Net income (loss) ( 196,027) 86,436 ( 109,591) Cash distributions ( 2,215,000) ( 114,133) ( 2,329,133) ---------- ------- ---------
Balance, Dec. 31, 1997 $4,512,996 ($171,438) $4,341,558 Net income 1,094,816 87,868 1,182,684 Cash distributions ( 2,076,000) ( 95,715) ( 2,171,715) --------- ------- ---------
Balance, Dec. 31, 1998 $3,531,812 ($179,285) $3,352,527 ========= ======= =========
The accompanying notes are an integral part of these financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-D
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-D, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-D Balance Sheets December 31, 1998 and 1997
ASSETS ------
1998 1997 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents $ 172,776 $ 298,964 Accounts receivable: Oil and gas sales 268,703 361,775 --------- --------- Total current assets $ 441,479 $ 660,739
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 1,236,882 2,211,248
DEFERRED CHARGE 9,462 18,875 --------- --------- $1,687,823 $2,890,862 ========= =========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 55,996 $ 114,286 Gas imbalance payable 4,454 - --------- ---------
Total current liabilities $ 60,450 $ 114,286
ACCRUED LIABILITY $ 182,639 $ 201,934
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 73,501) ($ 62,091) Limited Partners, issued and outstanding, 131,008 Units 1,518,235 2,636,733 --------- --------- Total Partners' capital $1,444,734 $2,574,642 --------- --------- $1,687,823 $2,890,862 ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-D Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------ --------- ------------
Balance, Dec. 31, 1995 $4,248,905 ($36,176) $4,212,729 Net income 795,298 59,929 855,227 Cash distributions ( 1,091,000) ( 73,967) ( 1,164,967) --------- ------ ---------
Balance, Dec. 31, 1996 $3,953,203 ($50,214) $3,902,989 Net income 35,530 54,213 89,743 Cash distributions ( 1,352,000) ( 66,090) ( 1,418,090) --------- ------ ---------
Balance, Dec. 31, 1997 $2,636,733 ($62,091) $2,574,642 Net income (loss) ( 84,498) 38,462 ( 46,036) Cash distributions ( 1,034,000) ( 49,872) ( 1,083,872) --------- ------ ---------
Balance, Dec. 31, 1998 $1,518,235 ( 73,501) $1,444,734 ========= ====== =========
The accompanying notes are an integral part of these financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-E
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-E, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-E Balance Sheets December 31, 1998 and 1997
ASSETS ------
1998 1997 ------------- ------------- CURRENT ASSETS: Cash and cash equivalents $ 483,197 $ 1,114,574 Accounts receivable: Oil and gas sales 820,078 1,361,797 ---------- ---------- Total current assets $1,303,275 $ 2,476,371
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 3,190,480 8,716,929
DEFERRED CHARGE 127,657 204,087 --------- ---------- $4,621,412 $11,397,387 ========= ==========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 302,889 $ 693,518 Gas imbalance payable 178,518 142,749 ---------- ---------- Total current liabilities $ 481,407 $ 836,267
ACCRUED LIABILITY $ 298,486 $ 320,943
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 275,783) ($ 209,050) Limited Partners, issued and outstanding, 418,266 Units 4,117,302 10,449,227 --------- ---------- Total Partners' capital $3,841,519 $10,240,177 --------- ---------- $4,621,412 $11,397,387 ========= ==========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-E Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------- ---------- -------------
Balance, Dec. 31, 1995 $16,319,788 ($127,750) $16,192,038 Net income 2,275,698 191,012 2,466,710 Cash distributions ( 3,624,000) ( 251,209) ( 3,875,209) ---------- ------- -----------
Balance, Dec. 31, 1996 $14,971,486 ($187,947) $14,783,539 Net income (loss) ( 219,259) 158,394 ( 60,865) Cash distributions ( 4,303,000) ( 179,497) ( 4,482,497) ---------- ------- ----------
Balance, Dec. 31, 1997 $10,449,227 ($209,050) $10,240,177 Net income (loss) ( 3,260,925) 57,256 ( 3,203,669) Cash distributions ( 3,071,000) ( 123,989) ( 3,194,989) ---------- ------- ----------
Balance, Dec. 31, 1998 $ 4,117,302 ($275,783) $ 3,841,519 ========== ======= ==========
The accompanying notes are an integral part of these financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-F
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-F, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-F Balance Sheets December 31, 1998 and 1997
ASSETS ------ 1998 1997 ------------ ------------- CURRENT ASSETS: Cash and cash equivalents $ 316,761 $ 541,382 Accounts receivable: Oil and gas sales 279,590 472,746 Other 9,631 9,631 --------- --------- Total current assets $ 605,982 $1,023,759
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 2,848,735 3,604,665
DEFERRED CHARGE 79,097 124,393 --------- --------- $3,533,814 $4,752,817 ========= =========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 133,841 $ 165,963 Gas imbalance payable 123,641 119,864 --------- ---------
Total current liabilities $ 257,482 $ 285,827
ACCRUED LIABILITY $ 171,735 $ 159,275
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 164,221) ($ 146,427) Limited Partners, issued and outstanding, 221,484 Units 3,268,818 4,454,142 --------- --------- Total Partners' capital $3,104,597 $4,307,715 --------- ---------
$3,533,814 $4,752,817 ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-F Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------- ---------- -------------
Balance, Dec. 31, 1995 $8,986,812 ($ 70,576) $8,916,236 Net income 483,478 72,299 555,777 Cash distributions ( 1,160,000) ( 99,246) ( 1,259,246) --------- ------- ---------
Balance, Dec. 31, 1996 $8,310,290 ($ 97,523) $8,212,767 Net income (loss) ( 2,273,148) 32,514 ( 2,240,634) Cash distributions ( 1,583,000) ( 81,418) ( 1,664,418) --------- ------- ---------
Balance, Dec. 31, 1997 $4,454,142 ($146,427) $4,307,715 Net income (loss) ( 5,324) 29,041 23,717 Cash distributions ( 1,180,000) ( 46,835) ( 1,226,835) --------- ------- ---------
Balance, Dec. 31, 1998 $3,268,818 ($164,221) $3,104,597 ========= ======= =========
The accompanying notes are an integral part of these financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE PARTNERS
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-G
In our opinion, the accompanying balance sheets and the related statements of operations, changes in partners' capital (deficit) and cash flows present fairly, in all material respects, the financial position of the Geodyne Energy Income Limited Partnership III-G, an Oklahoma 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 Partnership'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 February 13, 1999
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-G Balance Sheets December 31, 1998 and 1997
ASSETS ------ 1998 1997 ------------ ------------- CURRENT ASSETS: Cash and cash equivalents $ 169,558 $ 351,163 Accounts receivable: Oil and gas sales 163,801 285,689 General Partner - 13,140 Other 6,369 6,369 --------- --------- Total current assets $ 339,728 $ 656,361
NET OIL AND GAS PROPERTIES, utilizing the successful efforts method 1,427,362 2,141,289
DEFERRED CHARGE 50,380 75,406 --------- --------- $1,817,470 $2,873,056 ========= =========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) -------------------------------------------
CURRENT LIABILITIES: Accounts payable $ 73,835 $ 101,925 Gas imbalance payable 60,315 59,607 --------- ---------
Total current liabilities $ 134,150 $ 161,532
ACCRUED LIABILITY $ 111,221 $ 89,310
PARTNERS' CAPITAL (DEFICIT): General Partner ($ 99,974) ($ 85,608) Limited Partners, issued and outstanding, 121,925 Units 1,672,073 2,707,822 --------- --------- Total Partners' capital $1,572,099 $2,622,214 --------- ---------
$1,817,470 $2,873,056 ========= =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME LIMITED PARTNERSHIP III-G Statements of Partners' Capital (Deficit) For the Years Ended December 31, 1998, 1997, and 1996
Limited General Partners Partner Total ------------- ---------- ------------
Balance, Dec. 31, 1995 $5,136,727 ($26,964) $5,109,763 Net income 380,060 47,089 427,149 Cash distributions ( 721,000) ( 78,794) ( 799,794) --------- ------ ---------
Balance, Dec. 31, 1996 $4,795,787 ($58,669) $4,737,118 Net income (loss) ( 1,136,965) 22,672 ( 1,114,293) Cash distributions ( 951,000) ( 49,611) ( 1,000,611) --------- ------ ---------
Balance, Dec. 31, 1997 $2,707,822 ($85,608) $2,622,214 Net income (loss) ( 308,749) 13,093 ( 295,656) Cash distributions ( 727,000) ( 27,459) ( 754,459) --------- ------ ---------
Balance, Dec. 31, 1998 $1,672,073 ($99,974) $1,572,099 ========= ====== =========
The accompanying notes are an integral part of these financial statements.
GEODYNE ENERGY INCOME PROGRAM III LIMITED PARTNERSHIPS 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 Geodyne Energy Income Limited Partnerships (the "Partnerships") were formed pursuant to a public offering of depositary units ("Units"). Upon formation, investors became limited partners (the "Limited Partners") and held Units issued by each Partnership. Geodyne Resources, Inc. (the "General Partner") is the general partner of each Partnership. Limited Partner capital contributions were invested in producing oil and gas properties. The Partnerships were activated on the following dates with the following Limited Partner capital contributions.
Limited Partner Date of Capital Partnership Activation Contributions ----------- ------------------ ---------------
III-A November 21, 1989 $26,397,600 III-B January 24, 1990 13,833,600 III-C February 27, 1990 24,453,600 III-D September 5, 1990 13,100,800 III-E December 26, 1990 41,826,600 III-F March 7, 1991 22,148,400 III-G September 20, 1991 12,192,500
Pursuant to the terms of the partnership agreements for the Partnerships, the Partnerships will terminate on the following dates:
Partnerships Termination Date ------------ -----------------
III-A November 28, 1999 III-B January 24, 2000 III-C February 28, 2000 III-D September 5, 2000 III-E December 26, 2000 III-F March 7, 2001 III-G September 20, 2001
However, the General Partner may extend the term of each Partnership for up to five periods of two years each. As of the date of these financial statements, the General Partner intends to extend the term of the III-A, III-B, and III-C Partnerships for the first two-year extension period, but has not determined
whether it intends to (i) further extend the term of such Partnerships or (ii) extend the term of any other Partnership.
An affiliate of the General Partner owned the following Units at December 31, 1998:
Number of Percent of Partnership Units Owned Outstanding ----------- ----------- -----------
III-A 31,866 12.1% III-B 18,756 13.6% III-C 34,205 14.0% III-D 21,975 16.8% III-E 65,290 15.6% III-F 37,305 16.8% III-G 18,142 14.9%
The Partnerships' sole business is the development and production of oil and gas. Substantially all of the Partnerships' gas reserves are being sold regionally on 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 Partnerships' oil is sold at or near the Partnerships' wells under short-term purchase contracts at prevailing arrangements which are customary in the oil industry. The prices received for the Partnerships' oil and gas are subject to influences such as global consumption and supply trends. In 1998, the price of oil decreased to historically low levels. If the price of oil remains low, or if it decreases further, there may be a significant impact on the Partnerships' near-term results of operations and cash flows.
Allocation of Costs and Revenues
The terms of each Partnership's Limited Partnership Agreement (the "Partnership Agreement") allocate costs and income between the Limited Partners and the General Partner as follows:
Before Payout (1) After Payout(1) -------------------- -------------------- General Limited General Limited Partner Partners Partner Partners -------- -------- -------- -------- Costs(2) - ------------------------ Sales commissions, pay- ment for organization and offering costs and management fee 1% 99% - - Property acquisition costs 1% 99% 1% 99% Identified development drilling 1% 99% 1% 99% Development drilling(2) 5% 95% 15% 85% General and administra- tive costs, direct administrative costs and operating costs(2) 5% 95% 15% 85%
Income(2) - ------------------------ Temporary investments of Limited Partners' subscriptions 1% 99% 1% 99% Income from oil and gas production(2) 5% 95% 15% 85% Gain on sale of producing properties(2) 5% 95% 15% 85% All other income(2) 5% 95% 15% 85%
- ---------- (1) Payout occurs when total distributions to Limited Partners equal total original Limited Partner subscriptions. (2) If, at payout, the Limited Partners have received distributions at an annual rate less than 12% of their subscriptions, the percentage of income and costs allocated to the General Partner will increase to only 10% and the Limited Partners will be allocated 90%. Thereafter, if the distribution to Limited Partners reaches an average annual rate of 12% the allocation will change to 15% to the General Partner and 85% to the Limited Partners.
The III-B Partnership achieved payout during the first quarter of 1998. Beginning with the first quarter of 1998, operations for the III-B Partnership were allocated using the after payout percentages.
Cash and Cash Equivalents
The Partnerships consider 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 Partnerships to be subject to risk.
Credit Risks
Accrued oil and gas sales which are due from a variety of oil and gas purchasers subject the Partnerships to a concentration of credit risk. Some of these purchasers are discussed in Note 3 - Major Customers.
Oil and Gas Properties
The Partnerships follow the successful efforts method of accounting for their oil and gas properties. Under the successful efforts method, the Partnerships capitalize all property acquisition costs and development costs incurred in connection with the further development of oil and gas reserves. Property acquisition costs include costs incurred by the Partnerships or the General Partner to acquire producing properties, including related title insurance or examination costs, commissions, engineering, legal and accounting fees, and similar costs directly related to the acquisitions, plus an allocated portion of the General Partner's property screening costs. The acquisition cost to the Partnerships of properties acquired by the General Partner is adjusted to reflect the net cash results of operations, including interest incurred to finance the acquisition, for the period of time the properties are held by the General Partner. Leasehold impairment of unproved properties is recognized based upon an individual property assessment and exploratory experience. Upon discovery of commercial reserves, leasehold costs are transferred to producing properties.
Depletion of the costs of producing oil and gas properties, amortization of related intangible drilling and development costs, and depreciation of tangible lease and well equipment are computed on the units-of-production method. The Partnerships' calculation of depreciation, depletion, and amortization includes estimated dismantlement and abandonment costs, net of estimated salvage values. The depreciation, depletion, and amortization rates per equivalent barrel of oil produced during the years ended December 31, 1998, 1997, and 1996 were as follows:
Partnership 1998 1997 1996 ----------- ----- ----- -----
III-A $3.15 $3.42 $4.40 III-B 2.86 3.60 4.37 III-C 3.44 2.92 3.68 III-D 3.20 2.05 2.63 III-E 3.59 2.00 2.96 III-F 3.89 3.51 4.95 III-G 3.68 3.25 4.76
When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated with any gain or loss reflected in income. When less than complete units of depreciable property are retired or sold, the proceeds are credited to oil and gas properties.
The Partnerships evaluate the recoverability of the carrying costs of their proved oil and gas properties at the field level. If the unamortized costs of oil and gas properties within a field exceed the expected undiscounted future cash flows from such properties, the cost of the properties is written down to fair value, which is determined by using the discounted future cash flows from the properties. During 1998, 1997,and 1996, the Partnerships recorded the following non-cash charges against earnings (impairment provisions):
Partnership 1998 1997 1996 ----------- ---------- ---------- ----
III-A $ - $ 184,644 $ - III-B - 77,653 - III-C - 234,271 - III-D 506,636 485,820 - III-E 3,503,400 2,042,775 - III-F - 2,078,019 - III-G 310,413 1,113,114 -
The risk that the Partnerships will be required to record similar impairment provisions in the future increases as oil and gas prices decrease.
In addition, during 1997 the General Partner determined that the Partnerships' unproved properties would be uneconomic to develop and, therefore, of little or no value. This determination was based on an evaluation by the General Partner that it was unlikely that these unproved properties would be developed due to low oil and gas prices and provisions in the Partnership Agreements which limit the level of permissible drilling activity. As a result of this determination, the Partnership recorded the following noncash charges against earnings at March 31, 1997 in order to reflect the writing-off of the Partnerships' unproved properties:
Partnerships Amount ----------- ----------
III-A $1,432,362 III-B 660,469 III-C 1,462,146 III-D 446,423 III-E 850,663 III-F 806,386 III-G 438,666
Deferred Charge
Deferred Charge represents costs deferred for lease operating expenses incurred in connection with the Partnerships' 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 and 1997, cumulative total gas sales volumes for underproduced wells were less than the Partnerships' pro-rata share of total gas production from these wells by the following amounts:
1998 1997 -------------------- -------------------- Partnership Mcf Amount Mcf Amount ----------- ------- -------- ------- --------
III-A 435,225 $266,532 469,603 $199,722 III-B 247,738 193,310 261,654 136,296 III-C 161,424 70,849 188,244 86,649 III-D 11,977 9,462 20,653 18,875 III-E 78,791 127,657 129,793 204,087 III-F 63,675 79,097 101,297 124,393 III-G 34,495 50,380 53,170 75,406
Accrued Liability
Accrued liability represents charges accrued for lease operating expenses incurred in connection with the Partnerships' 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 and 1997, cumulative total gas sales volumes for overproduced wells exceeded the Partnerships' pro-rata share of total gas production from these wells by the following amounts:
1998 1997 -------------------- -------------------- Partnership Mcf Amount Mcf Amount ----------- ------- -------- ------- --------
III-A 125,481 $ 76,845 122,044 $ 51,905 III-B 53,103 41,436 54,702 28,494 III-C 345,570 151,671 310,293 142,828 III-D 231,188 182,639 220,959 201,934 III-E 184,228 298,486 204,110 320,943 III-F 138,251 171,735 129,703 159,275 III-G 76,153 111,221 62,974 89,310
Oil and Gas Sales and Gas Imbalance Payable
The Partnerships' oil and condensate production is sold, title passed, and revenue recognized at or near the Partnerships' wells under short-term purchase contracts at prevailing prices in accordance with arrangements which are customary in the oil and gas industry. Sales of gas applicable to the Partnerships' interest in producing oil and gas leases are recorded as revenue when the gas is metered and title transferred pursuant to the gas sales contracts covering the Partnerships' interest in gas reserves. During such times as a Partnership's sales of gas exceed its pro rata ownership in a well, such sales are recorded as revenue unless total sales from the well have exceeded the Partnership'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 Partnerships are currently settling this liability. At December 31, 1998 and 1997 total sales exceeded the Partnerships' share of estimated total gas reserves as follows:
1998 1997 -------------------- -------------------- Partnership Mcf Amount Mcf Amount ----------- ------- -------- ------- --------
III-A 20,602 $ 30,903 25,612 $ 38,418 III-B 12,281 18,422 4,451 6,676 III-C 16,986 25,479 20,329 30,493 III-D 2,969 4,454 - - III-E 119,012 178,518 95,166 142,749 III-F 82,427 123,641 79,909 119,864 III-G 40,210 60,315 39,738 59,607
These amounts were recorded as gas imbalance payables in accordance with the sales method. These gas imbalance payables will be settled by either gas production by the underproduced
party in excess of the current estimates of total gas reserves for the well or by a negotiated or contractual payment to the underproduced party.
General and Administrative Overhead
The General Partner and its affiliates are reimbursed for actual general and administrative costs incurred and attributable to the conduct of the business affairs and operations of the Partnerships.
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 or incurred 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 these financial statements.
2. TRANSACTIONS WITH RELATED PARTIES
The Partnerships reimburse the General Partner for the general and administrative overhead applicable to the Partnerships, based on an allocation of actual costs incurred by the General Partner. When actual costs incurred benefit other Partnerships and affiliates, the allocation of costs is based on the relationship of the Partnerships' reserves to the total reserves owned by all Partnerships and affiliates. The General Partner believes this allocation method is reasonable. Although the actual costs incurred by the General Partner and its affiliates have fluctuated during the three years presented, the amounts charged to the Partnerships have not fluctuated due to the expense limitations imposed by the Partnership Agreement. The following is a summary of payments made to the General Partner or its affiliates by the Partnerships for general and
administrative overhead costs for the years ended December 31, 1998, 1997, and 1996:
Partnership 1998 1997 1996 ----------- -------- -------- --------
III-A $277,872 $277,872 $277,872 III-B 145,620 145,620 145,620 III-C 257,412 257,412 257,412 III-D 137,904 137,904 137,904 III-E 440,280 440,280 440,280 III-F 233,136 233,136 233,136 III-G 128,340 128,340 128,340
Affiliates of the Partnerships operate certain of the Partnerships' properties and their policy is to bill the Partnerships 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 table sets forth purchasers who individually accounted for ten percent or more of each Partnership's combined oil and gas sales during 1998, 1997, and 1996:
Partnership Purchaser Percentage ----------- ------------------------ -------------------------- 1998 1997 1996 ----- ----- -----
III-A El Paso Energy Marketing Company ("El Paso") 33.9% 47.2% 59.2% Valero Industrial Gas L.P. ("Valero") 30.8% 14.4% - % Phibro Energy, Inc. ("Phibro") 17.0% - % - % Mesa Operating Ltd. Partnership ("Mesa") - % - % 19.4%
III-B El Paso 26.7% 37.9% 47.9% Valero 23.9% 11.4% - % Phibro 18.7% 12.7% - % Sun Refining & Marketing Company 14.4% 13.1% 10.3% Mesa - % - % 22.0%
III-C El Paso 55.5% 49.8% 51.2%
III-D El Paso 54.9% 45.6% 44.4% Eaglwing Trading, Inc. ("Eaglwing") 15.3% 18.3% - % Oryx Energy Company ("Oryx") - % - % 19.9%
III-E Eaglwing 30.1% 33.3% - % El Paso 12.6% 12.4% 12.3% Oryx - % - % 36.5% Hunt Energy Corp. - % - % 10.0%
III-F El Paso 28.3% 28.5% 25.9% Amoco Production Company ("Amoco") - % - % 10.4%
III-G El Paso 24.5% 23.9% 21.6% Amoco - % - % 10.9%
In the event of interruption of purchases by one or more of these significant customers or the cessation or material change in availability of open access transportation by the Partnerships' pipeline transporters, the Partnerships may encounter difficulty in marketing their 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 Partnerships is presented pursuant to the disclosure requirements promulgated by the SEC.
Capitalized Costs
Capitalized costs and accumulated depreciation, depletion, amortization, and valuation allowance at December 31, 1998 and 1997 were as follows:
III-A Partnership -----------------
1998 1997 ------------- -------------
Proved properties $15,792,267 $15,907,665
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 13,569,594) ( 13,237,716) ---------- ---------- Net oil and gas Properties $ 2,222,673 $ 2,669,949 ========== ==========
III-B Partnership -----------------
1998 1997 ------------ ------------- Proved properties $ 9,325,381 $9,402,262
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 8,083,001) ( 7,903,114) ---------- ---------- Net oil and gas Properties $ 1,242,380 $1,499,148 ========== ==========
III-C Partnership -----------------
1998 1997 ------------- ------------- Proved properties $19,181,561 $19,627,883
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 16,401,716) ( 16,185,252) ---------- ----------
Net oil and gas Properties $ 2,779,845 $ 3,442,631 ========== ==========
III-D Partnership -----------------
1998 1997 ------------- ------------- Proved properties $12,039,032 $12,187,201
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 10,802,150) ( 9,975,953) ---------- ----------
Net oil and gas Properties $ 1,236,882 $ 2,211,248 ========== ==========
III-E Partnership -----------------
1998 1997 ------------- ------------- Proved properties $34,096,393 $34,159,634
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 30,905,913) ( 25,442,705) ---------- ----------
Net oil and gas Properties $ 3,190,480 $ 8,716,929 ========== ==========
III-F Partnership -----------------
1998 1997 ------------- ------------- Proved properties $16,559,050 $16,673,217
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 13,710,315) ( 13,068,552) ---------- ----------
Net oil and gas Properties $ 2,848,735 $ 3,604,665 ========== ==========
III-G Partnership -----------------
1998 1997 ------------ ------------- Proved properties $ 9,515,195 $9,602,310
Less accumulated depreciation, depletion, amorti- zation, and valua- tion allowance ( 8,087,833) ( 7,461,021) ---------- ---------
Net oil and gas properties $ 1,427,362 $2,141,289 ========== =========
Costs Incurred
The III-A and III-B Partnerships incurred acquisition costs of $35,246 and $23,248, respectively, during the year ended December 31, 1997 for additional acreage underlying the Lebleu No. 4 well. The Partnerships incurred no other costs in connection with oil and gas acquisition or exploration activities during the years ended December 31, 1998, 1997, and 1996. Costs incurred by the Partnerships in connection with oil and gas property development activities for the years ended December 31, 1998, 1997, and 1996 were as follows:
Partnership 1998 1997 1996 ----------- -------- -------- --------
III-A $ 55,973 $ 40,203 $ 4,548 III-B 11,667 20,491 21,881 III-C 123,095 104,670 24,068 III-D 64,034 579 24,953 III-E 2,926 65,616 37,987 III-F - 34,952 12,107 III-G 11,316 28,338 19,668
Quantities of Proved Oil and Gas Reserves - Unaudited
The following tables summarize changes in net quantities of the Partnerships' proved reserves, all of which are located in the United States, for the periods indicated. The proved reserves at December 31, 1998, 1997, and 1996 were estimated by petroleum engineers employed by affiliates of the Partnerships. Certain reserve information was reviewed by Ryder Scott Company Petroleum Engineers, an independent petroleum engineering firm. The following information includes certain gas balancing adjustments which caused the gas volumes to differ from the
reserve reports prepared by the General Partner and reviewed by Ryder Scott.
III-A Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) --------- -----------
Proved reserves, Dec. 31, 1995 173,001 6,996,352 Production ( 46,923) (1,268,943) Sale of minerals in place ( 1,434) ( 417,113) Revision of previous estimates 29,255 871,973 ------- ---------
Proved reserves, Dec. 31, 1996 153,899 6,182,269 Production ( 40,468) (1,031,152) Sale of minerals in place ( 4,695) ( 661,004) Extensions and discoveries 6 915 Revision of previous estimates 4,121 740,812 ------- ---------
Proved reserves, Dec. 31, 1997 112,863 5,231,840 Production ( 34,689) ( 741,990) Sale of minerals in place ( 170) ( 37,253) Extensions and discoveries 7,433 175,973 Revision of previous estimates 6,687 100,845 ------- ---------
Proved reserves, Dec. 31, 1998 92,124 4,729,415 ======= =========
PROVED DEVELOPED RESERVES: December 31, 1996 142,520 5,999,778 ======= ========= December 31, 1997 101,190 5,027,338 ======= ========= December 31, 1998 86,204 4,604,490 ======= =========
III-B Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) --------- ------------
Proved reserves, Dec. 31, 1995 122,916 3,464,971 Production ( 37,849) ( 642,152) Sale of minerals in place ( 624) ( 186,418) Revision of previous estimates 36,520 331,501 ------- ---------
Proved reserves, Dec. 31, 1996 120,963 2,967,902 Production ( 37,216) ( 518,891) Sale of minerals in place ( 2,009) ( 285,841) Revision of previous estimates 11,805 370,683 ------- ---------
Proved reserves, Dec. 31, 1997 93,543 2,533,853 Production ( 34,221) ( 355,197) Sale of minerals in place ( 98) ( 46,674) Revision of previous estimates 31,939 42,054 ------- ---------
Proved reserves, Dec. 31, 1998 91,163 2,174,036 ======= =========
PROVED DEVELOPED RESERVES: December 31, 1996 117,345 2,906,514 ======= ========= December 31, 1997 89,784 2,462,219 ======= ========= December 31, 1998 87,403 2,105,919 ======= =========
III-C Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) --------- ------------
Proved reserves, Dec. 31, 1995 108,468 7,902,210 Production ( 27,429) (1,351,525) Sale of minerals in place ( 1,266) ( 132,327) Extensions and discoveries 10,541 157,345 Revision of previous estimates 72,173 1,144,100 ------- ---------
Proved reserves, Dec. 31, 1996 162,487 7,719,803 Production ( 27,069) (1,124,237) Sale of minerals in place ( 4,753) ( 197,339) Extensions and discoveries 447 - Revision of previous estimates 22,200 781,366 ------- ---------
Proved reserves, Dec. 31, 1997 153,312 7,179,593 Production ( 22,980) (1,156,387) Sale of minerals in place ( 5,849) ( 322,985) Extensions and discoveries 444 443,959 Revision of previous estimates 9,742 ( 375,699) ------- ---------
Proved reserves, Dec. 31, 1998 134,669 5,768,481 ======= =========
PROVED DEVELOPED RESERVES: December 31, 1996 162,235 7,673,323 ======= ========= December 31, 1997 153,112 7,157,512 ======= ========= December 31, 1998 134,527 5,754,200 ======= =========
III-D Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) --------- ------------
Proved reserves, Dec. 31, 1995 421,914 3,970,007 Production ( 41,351) ( 760,593) Sale of minerals in place ( 427) ( 25,031) Extensions and discoveries 1,509 27,059 Revision of previous estimates 48,985 558,104 ------- ---------
Proved reserves, Dec. 31, 1996 430,630 3,769,546 Production ( 40,758) ( 708,262) Sale of minerals in place ( 396) ( 18,762) Extensions and discoveries 94 1,797 Revision of previous estimates 88,825 760,231 ------- ---------
Proved reserves, Dec. 31, 1997 478,395 3,804,550 Production ( 35,908) ( 767,089) Sale of minerals in place ( 1,822) ( 48,776) Extensions and discoveries 370 361,916 Revision of previous estimates (315,169) ( 511,711) ------- ---------
Proved reserves, Dec. 31, 1998 125,866 2,838,890 ======= =========
PROVED DEVELOPED RESERVES: December 31, 1996 430,606 3,764,539 ======= ========= December 31, 1997 478,386 3,803,645 ======= ========= December 31, 1998 125,866 2,838,890 ======= =========
III-E Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) ----------- ------------
Proved reserves, Dec. 31, 1995 2,587,479 12,820,859 Production ( 229,226) ( 2,152,599) Sale of minerals in place ( 3,259) ( 190) Extensions and discoveries 4,252 30,349 Revision of previous estimates 258,393 ( 922,682) --------- ----------
Proved reserves, Dec. 31, 1996 2,617,639 9,775,737 Production ( 235,152) ( 2,189,619) Sale of minerals in place ( 2,156) ( 245,398) Extensions and discoveries - 11,997 Revision of previous estimates 631,209 2,780,432 --------- ----------
Proved reserves, Dec. 31, 1997 3,011,540 10,133,149 Production ( 223,936) ( 1,974,917) Sale of minerals in place ( 669) ( 57,652) Revision of previous estimates (2,185,625) ( 84,105) --------- ----------
Proved reserves, Dec. 31, 1998 601,310 8,016,475 ========= ==========
PROVED DEVELOPED RESERVES: December 31, 1996 2,617,639 9,775,737 ========= ========== December 31, 1997 3,011,540 10,133,149 ========= ========== December 31, 1998 601,310 8,016,475 ========= ==========
III-F Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) --------- ------------
Proved reserves, Dec. 31, 1995 467,066 7,054,686 Production ( 74,064) ( 924,827) Sale of minerals in place ( 14,255) ( 8,294) Extensions and discoveries 3,560 - Revision of previous estimates 109,006 ( 454,833) ------- ---------
Proved reserves, Dec. 31, 1996 491,313 5,666,732 Production ( 65,787) ( 898,447) Sale of minerals in place ( 5,981) ( 169,022) Extensions and discoveries 10,573 99,305 Revision of previous estimates ( 30,372) 905,241 ------- ---------
Proved reserves, Dec. 31, 1997 399,746 5,603,809 Production ( 54,002) ( 787,609) Sale of minerals in place ( 854) ( 49,751) Revision of previous estimates (113,008) ( 39,496) ------- ---------
Proved reserves, Dec. 31, 1998 231,882 4,726,953 ======= =========
PROVED DEVELOPED RESERVES: December 31, 1996 491,313 5,666,732 ======= ========= December 31, 1997 399,746 5,603,809 ======= ========= December 31, 1998 231,882 4,726,953 ======= =========
III-G Partnership -----------------
Crude Natural Oil Gas (Barrels) (Mcf) --------- ----------
Proved reserves, Dec. 31, 1995 352,310 3,865,551 Production ( 54,083) ( 499,884) Sale of minerals in place ( 11,160) ( 10,142) Extensions and discoveries 5,358 3,275 Revision of previous estimates 77,164 ( 321,474) ------- ---------
Proved reserves, Dec. 31, 1996 369,589 3,037,326 Production ( 47,493) ( 500,966) Sale of minerals in place ( 6,363) ( 92,435) Extensions and discoveries 7,164 66,081 Revision of previous estimates ( 19,969) 486,311 ------- ---------
Proved reserves, Dec. 31, 1997 302,928 2,996,317 Production ( 38,858) ( 419,813) Sale of minerals in place ( 489) ( 29,446) Extensions and discoveries 693 19,866 Revision of previous estimates ( 92,484) ( 41,204) ------- ---------
Proved reserves, Dec. 31, 1998 171,790 2,525,720 ======= =========
PROVED DEVELOPED RESERVES: December 31, 1996 369,589 3,037,326 ======= ========= December 31, 1997 302,928 2,996,317 ======= ========= December 31, 1998 171,790 2,525,720 ======= =========
Standardized Measure of Discounted Future Net Cash Flows of Proved Oil and Gas Reserves - Unaudited
The following tables set forth each of the Partnerships' estimated future net cash flows as of December 31, 1998 relating to proved oil and gas reserves based on the standardized measure as prescribed in SFAS No. 69:
Partnership -------------------------------- III-A III-B ------------- ------------ Future cash inflows $11,039,349 $5,528,827 Future production and development costs ( 3,235,761) ( 1,700,915) ---------- ---------
Future net cash flows $ 7,803,588 $3,827,912
10% discount to reflect timing of cash flows ( 2,422,763) ( 1,160,225) ---------- ---------
Standardized measure of discounted future net cash flows $ 5,380,825 $2,667,687 ========== =========
Partnership --------------------------------- III-C III-D ------------- ------------- Future cash inflows $12,793,855 $6,796,300 Future production and development costs ( 4,531,622) ( 3,014,891) ---------- ---------
Future net cash flows $ 8,262,233 $3,781,409
10% discount to reflect timing of cash flows ( 2,833,364) ( 1,054,199) ---------- ---------
Standardized measure of discounted future net cash flows $ 5,428,869 $2,727,210 ========== =========
Partnership --------------------------------- III-E III-F ------------- ------------- Future cash inflows $23,118,031 $11,451,629 Future production and development costs ( 12,488,333) ( 4,745,163) ---------- ----------
Future net cash flows $10,629,698 $ 6,706,466
10% discount to reflect timing of cash flows ( 3,773,041) ( 2,543,451) ---------- ----------
Standardized measure of discounted future net cash flows $ 6,856,657 $ 4,163,015 ========== ==========
Partnership ------------- III-G ------------- Future cash inflows $ 6,602,025 Future production and development costs ( 2,876,655) ----------
Future net cash flows $ 3,725,370
10% discount to reflect timing of cash flows ( 1,414,866) ----------
Standardized measure of discounted future net cash flows $ 2,310,504 ==========
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 Partnerships' reserves were determined at December 31, 1998 using oil and gas prices of $9.50 per barrel and $2.03 per Mcf, respectively.
INDEX TO EXHIBITS -----------------
Number Description - ------ -----------
4.1 The Certificate and Agreements of Limited Partnership for the following Partnerships have been previously filed with the Securities and Exchange Commission as Exhibit 2.1 to Form 8-A filed by each Partnership on the dates shown below and are hereby incorporated by reference.
Partnership Filing Date File No. ----------- ----------- --------
III-A February 20, 1990 0-18302 III-B March 30, 1990 0-18636 III-C March 30, 1990 0-18634 III-D November 14, 1990 0-18936 III-E January 22, 1991 0-19010 III-F March 25, 1991 0-19102 III-G September 30, 1991 0-19563
4.2 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-A, filed as Exhibit 4.1 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.3 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-B, filed as Exhibit 4.2 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.4 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-C, filed as Exhibit 4.3 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.5 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-D, filed as Exhibit 4.4 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.6 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-E, filed as Exhibit 4.5 to Registrant's Current Report on Form
8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.7 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-F, filed as Exhibit 4.6 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.8 Second Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-G, filed as Exhibit 4.7 to Registrant's Current Report on Form 8-K dated August 2, 1993 filed with the SEC on August 10, 1993 and is hereby incorporated by reference.
4.9 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-A, filed as Exhibit 4.10 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.10 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-B, filed as Exhibit 4.11 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.11 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-C, filed as Exhibit 4.12 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.12 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-D, filed as Exhibit 4.13 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.13 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-E, filed as Exhibit 4.14 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
4.14 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-F, filed as Exhibit 4.15 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with
the SEC on April 1, 1996 and is hereby incorporated by reference.
4.15 Third Amendment to Agreement of Limited Partnership of Geodyne Energy Income Limited Partnership III-G, filed as Exhibit 4.16 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 filed with the SEC on April 1, 1996 and is hereby incorporated by reference.
*23.1 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-A.
*23.2 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-B.
*23.3 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-C.
*23.4 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-D.
*23.5 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-E.
*23.6 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-F.
*23.7 Consent of Ryder Scott Company, Petroleum Engineers for Geodyne Energy Income Limited Partnership III-G.
*27.1 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-A'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 Geodyne Energy Income Limited Partnership III-B's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
*27.3 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-C's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
*27.4 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-D's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
*27.5 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-E's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
*27.6 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-F's financial statements as of December 31, 1998 and for the year ended December 31, 1998.
*27.7 Financial Data Schedule containing summary financial information extracted from the Geodyne Energy Income Limited Partnership III-G'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.