Item 1. Business
General Southwest Royalties Institutional Income Fund X-C, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on September 20, 1991. The offering of limited partnership interests began October 1, 1991, reached minimum capital requirements on January 28, 1992, and concluded April 30, 1992. The Partnership has no subsidiaries.
The Partnership has acquired interests in producing oil and gas properties, produced and marketed the crude oil and natural gas from such properties. In most cases, the Partnership purchased royalty or overriding royalty interests and working interests in oil and gas properties that were converted into net profits interests or other non-operating interests. The Partnership purchased either all or part of the rights and obligations under various oil and gas leases.
The principal executive offices of the Partnership are located at 407 N. Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner of the Partnership, Southwest Royalties, Inc. (the "Managing General Partner") and its staff of 89 individuals, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of oil and gas properties and the marketing of production from such properties. H. H. Wommack, III, a stockholder, director, President and Treasurer of the Managing General Partner, is also a general partner. The Partnership has no employees.
Principal Products, Marketing and Distribution The Partnership has acquired and holds royalty interests and net profit interests in oil and gas properties located in New Mexico and Texas. All activities of the Partnership are confined to the continental United States. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business.
The revenues generated from the Partnership's oil and gas activities are dependent upon the current market for oil and gas. The prices received by the Partnership for its oil and gas production depend upon numerous factors beyond the Partnership's control, including competition, economic, political and regulatory developments and competitive energy sources, and make it particularly difficult to estimate future prices of oil and natural gas.
For nearly nine months, despite the fears of a global recession, crude oil prices held steady between $26 and $28 per barrel due in part to a series of OPEC and non-OPEC production cuts. Then, following what has become known simply as "9-11", crude prices plunged immediately to $22 and gradually fell to below $18 per barrel. Slower demand across the U.S. caused by the threat of recession and warmer than expected weather also led to declining prices in the latter half of 2001. However, the oil cartel and other non-member countries agreed for the fourth time since February to curb output in an effort to stabilize prices. Crude oil contracts trading on the NYMEX closed the year at approximately $20 per barrel.
Spot prices in 2001 climbed to their highest levels ever, with the yearly average price nationwide reaching $4.14/MMBtu, up 9.77% from the 2000 average of $3.77/MMBtu. Prices reached their zenith in the first quarter of 2001 before beginning a steady decline throughout the remainder of the year. The terrorist attacks of September 11 knocked the New York Mercantile Exchange out of the market for several days and shook the spot marketplace into a maintenance mode. As companies measured the impact of the attacks on the U.S. economy, spot prices deteriorated further. In the fourth quarter, prices bottomed out for the year with the three-month average falling to $2.31/MMBtu. As for 2002, record-high storage levels and the expectation of a flat economy through the first half of the year are leading industry experts to predict prices to average $2.05/MMBtu, remaining above the $2.00 per MMBtu level for a 5th consecutive year.
Following is a table of the ratios of revenues received from oil and gas production for the last three years:
Oil Gas
2001 78% 22% 2000 88% 12% 1999 84% 16%
As the table indicates, the majority of the Partnership's revenue is from its oil production, and Partnership revenues will be highly dependent upon the future prices and demands for oil.
Seasonality of Business Although the demand for natural gas is highly seasonal, with higher demand in the colder winter months and in very hot summer months, the Partnership has been able to sell all of its natural gas, either through contracts in place or on the spot market at the then prevailing spot market price. As a result, the volumes sold by the Partnership have not fluctuated materially with the change of season.
Customer Dependence No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 77% of the Partnership's total oil and gas production during 2001: Teppco Crude Oil LLC for 65% and Plains Marketing LP for 12%. Two purchasers accounted for 84% of the Partnership's total oil and gas production during 2000: Teppco Crude Oil LLC for 72% and Plains Marketing LP for 12%. Two purchasers accounted for 79% of the Partnership's total oil and gas production during 1999: Teppco Crude Oil LLC for 68% and Scurlock Permian LLC for 11%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's sales of oil and gas production.
Competition Because the Partnership has utilized all of its funds available for the acquisition of interests in producing oil and gas properties, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties.
Factors that may adversely affect the Partnership include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.
Regulation
Oil and Gas Production - The production and sale of oil and gas is subject to federal and state governmental regulation in several respects, such as existing price controls on natural gas and possible price controls on crude oil, regulation of oil and gas production by state and local governmental agencies, pollution and environmental controls and various other direct and indirect regulation. Many jurisdictions have periodically imposed limitations on oil and gas production by restricting the rate of flow for oil and gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of wells. The federal government has the power to permit increases in the amount of oil imported from other countries and to impose pollution control measures.
Various aspects of the Partnership's oil and gas activities are regulated by administrative agencies under statutory provisions of the states where such activities are conducted and by certain agencies of the federal government for operations on Federal leases. Moreover, certain prices at which the Partnership may sell its natural gas production are controlled by the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act of 1989 and the regulations promulgated by the Federal Energy Regulatory Commission.
Environmental - The Partnership's oil and gas activities are subject to extensive federal, state and local laws and regulations governing the generation, storage, handling, emission, transportation and discharge of materials into the environment. Governmental authorities have the power to enforce compliance with their regulations, and violations carry substantial penalties. This regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. The Managing General Partner is unable to predict what, if any, effect compliance will have on the Partnership.
Industry Regulations and Guidelines - Certain industry regulations and guidelines apply to the registration, qualification and operation of oil and gas programs in the form of limited partnerships. The Partnership is subject to these guidelines which regulate and restrict transactions between the Managing General Partner and the Partnership. The Partnership complies with these guidelines and the Managing General Partner does not anticipate that continued compliance will have a material adverse effect on Partnership operations.
Partnership Employees The Partnership has no employees; however the Managing General Partner has a staff of geologists, engineers, accountants, landmen and clerical staff who engage in Partnership activities and operations and perform additional services for the Partnership as needed. In addition to the Managing General Partner's staff, the Partnership engages independent consultants such as petroleum engineers and geologists as needed. As of December 31, 2001, there were 89 individuals directly employed by the Managing General Partner in various capacities.
Item 2.
Item 2. Properties
In determining whether an interest in a particular producing property was to be acquired, the Managing General Partner considered such criteria as estimated oil and gas reserves, estimated cash flow from the sale of production, present and future prices of oil and gas, the extent of undeveloped and unproved reserves, the potential for secondary, tertiary and other enhanced recovery projects and the availability of markets.
As of December 31, 2001, the Partnership possessed an interest in oil and gas properties located in; Chaves, Eddy and Lea Counties of New Mexico; and Colorado, Comanche, Glasscock, Howard, Martin, Midland, Mitchell, Scurry, Throckmorton, Tom Green and Winkler Counties of Texas. These properties consist of various interests in 470 wells and units.
Due to the Partnership's objective of maintaining current operations without engaging in the drilling of any developmental or exploratory wells, or additional acquisitions of producing properties, there have not been any significant changes in properties during 2001, 2000 and 1999.
During 2001 and 2000, there were no property sales. During 1999, eight leases were sold for approximately $18,644.
Significant Properties The following table reflects the significant properties in which the Partnership has an interest:
Date Purchased No. of Proved Reserves* Name and Location and Interest Wells Oil (bbls) Gas (mcf) - ----------------- ------------ ----- ---------- --------- Ackerly-Ira-Sharon 10/92 at 4% 405 17,000 68,000 Ridge Acquisition to 50% net Scurry, Mitchell profits interest and Martin Counties, Texas
Kelt Ohio 1/94 at 25% 1 1,000 253,000 Chaves County, to 50% net New Mexico profits interest
Mettie Poole #1 10/92 at 11% 1 1,000 55,000 Colorado County, net profits Texas interest
*Ryder Scott Petroleum Engineers prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.
Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.66 per barrel.
Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $1.65 per Mcf.
As also discussed in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, oil and gas prices were subject to frequent changes in 2001.
The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves.
Because the Partner does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.
The Partnership or the owners of properties in which the Partnership owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 3.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is a party.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2001 through the solicitation of proxies or otherwise.
Part II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
Market Information
Limited partnership interests, or units, in the Partnership were initially offered and sold for a price of $500. Limited partner units are not traded on any exchange and there is no public or organized trading market for them. The Managing General Partner has become aware of certain limited and sporadic transfers of units between limited partners and third parties, but has no verifiable information regarding the prices at which such units have been transferred. Further, a transferee may not become a substitute limited partner without the consent of the Managing General Partner.
The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion. In 2001, 10.5 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $132.66 per unit. In 2000, 30 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $56.14 per unit. As of December 31, 1999, no limited partner units were purchased by the Managing General Partner.
Number of Limited Partner Interest Holders
As of December 31, 2001, there were 334 holders of limited partner units in the Partnership.
Distributions
Pursuant to Article III, Section 3.05 of the Partnership's Certificate and Agreement of Limited Partnership "Net Cash Flow" is distributed to the partners on a quarterly basis. "Net Cash Flow" is defined as "the cash generated by the Partnership's investments in producing oil and gas properties, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of the Partnership, as determined in the sole discretion of the Managing General Partner."
During 2001, quarterly distributions were made totaling $330,587, with $297,528 distributed to the limited partners and $33,059 to the general partners. For the year ended December 31, 2001, distributions of $49.73 per limited partner unit were made, based upon 5,983 limited partner units outstanding. During 2000, quarterly distributions were made totaling $286,050, with $257,445 distributed to the limited partners and $28,605 to the general partners. For the year ended December 31, 2000, distributions of $43.03 per limited partner unit were made, based upon 5,983 limited partner units outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $74,277, with $68,477 distributed to the limited partners and $5,800 to the general partners. For the year ended December 31, 1999, distributions of $11.45 per limited partner unit were made, based upon 5,983 limited partner units outstanding.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31 2001, 2000, 1999, 1998 and 1997 should be read in conjunction with the financial statements included in Item 8:
Year ended December 31, ------------------------------------------------- 2001 2000 1999 1998 1997 ---- ---- ---- ---- ----
Revenues $ 223,520 390,141 180,963 88,003 427,561
Net income (loss) 76,865 318,946 99,087 (149,133) 235,030
Partners' share of net income (loss):
General partners 18,287 34,995 13,909 3,687 38,403
Limited partners 58,579 283,951 85,178 (152,820) 196,627
Limited partners' net income (loss) per unit 9.79 47.46 14.24 (25.54) 32.86
Limited partners' cash distribution per unit 49.73 43.03 11.45 17.37 84.16
Total assets $ 206,456 460,179 427,285 402,489 667,106
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
The Partnership was formed to acquire non-operating interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. Net revenues from producing oil and gas properties are not reinvested in other revenue producing assets except to the extent that producing facilities and wells are reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves. The economic life of the Partnership thus depends on the period over which the Partnership's oil and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, lease operating expenses, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements and on the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately. Net income available for distribution to the limited partners is therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. The partnership will most likely experience the historical production decline of approximately 9% per year.
Critical Accounting Policies Full cost ceiling calculations The Partnership follows the full cost method of accounting for its oil and gas properties. The full cost method subjects companies to quarterly calculations of a "ceiling", or limitation on the amount of properties that can be capitalized on the balance sheet. If the Partnership's capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. The Partnership's reserve estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than the Partnership's long-term price forecast that is a barometer for true fair value.
The Partnership's policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.
Results of Operations
A. General Comparison of the Years Ended December 31, 2001 and 2000
The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:
Year Ended Percentage December 31, Increase 2001 2000 (Decrease) ---- ---- --------- Average price per barrel of oil $ 21.52 27.70 (22%) Average price per mcf of gas $ 3.91 3.73 5% Oil production in barrels 28,700 30,400 (6%) Gas production in mcf 43,500 30,100 45% Income from net profits interests $ 220,775 386,562 (43%) Partnership distributions $ 330,587 286,050 15% Limited partner distributions $ 297,528 257,445 15% Per unit distribution to limited partners $ 49.73 43.03 15% Number of limited partner units 5,983 5,983
Revenues
The Partnership's income from net profits interests decreased to $220,775 from $386,562 for the years ended December 31, 2001 and 2000, respectively, a decrease of 43%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:
1. The average price for a barrel of oil received by the Partnership decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 22%, or $6.18 per barrel, resulting in a decrease of approximately $177,400 in income from net profits interests. Oil sales represented 78% of total oil and gas sales during the year ended December 31, 2001 as compared to 88% during the year ended December 31, 2000.
The average price for an mcf of gas received by the Partnership increased during the same period by 5%, or $.18 per mcf, resulting in an increase of approximately $7,800 in income from net profits interests.
The net total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $169,600. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 1,700 barrels or 6% during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $47,100 in income from net profits interests.
Gas production increased approximately 13,400 mcf or 45% during the same period, resulting in an increase of approximately $50,000 in income from net profits interests.
The net total increase in income from net profits interests due to the change in production is approximately $2,900. The Partnership's dramatic increase in gas production was primarily in connection with one well. The partnership was informed during that a workover which was performed during the last quarter of 1999 on a non-operated well was not only unsuccessful but caused the well to shut down. This well was not believed to be recoverable, thus the loss to the Partnership was considered to be permanent. This well represented approximately 1,320 mcf a month. Total decline for the partnership during the year ended December 31, 2000 in connection with this non-operated well was approximately 15,700 mcf. During 2001, this well was successfully recovered and brought back online, producing approximately 930 mcf a month.
3. Lease operating costs and production taxes were less than 1% lower, or approximately $1,300 less during the year ended December 31, 2001 as compared to the year ended December 31, 2000.
Costs and Expenses
Total costs and expenses increased to $146,655 from $71,195 for the years ended December 31, 2001 and 2000, respectively, an increase of 106%. The increase is the result of higher depletion expense and general and administrative costs.
1. General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs increased 1% or approximately $500 during the year ended December 31, 2001 as compared to the year ended December 31, 2000.
2. Depletion expense increased to $106,000 for the year ended December 31, 2001 from $31,000 for the same period in 2000. This represents an increase of 242%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by the Partnership's independent petroleum consultants.
The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine the Partnership's reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by the Partnership during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $39,000 as of December 31, 2000.
Results of Operations
B. General Comparison of the Years Ended December 31, 2000 and 1999
The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:
Year Ended Percentage December 31, Increase 2000 1999 (Decrease) ---- ---- --------- Average price per barrel of oil $ 27.70 16.32 70% Average price per mcf of gas $ 3.73 2.14 74% Oil production in barrels 30,400 34,820 (13%) Gas production in mcf 30,100 49,970 (40%) Income from net profits interests $ 386,562 180,192 115% Partnership distributions $ 286,050 74,277 285% Limited partner distributions $ 257,445 68,477 276% Per unit distribution to limited partners $ 43.03 11.45 276% Number of limited partner units 5,983 5,983
Revenues
The Partnership's income from net profits interests increased to $386,562 from $180,192 for the years ended December 31, 2000 and 1999, respectively, an increase of 115%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 70%, or $11.38 per barrel, resulting in an increase of approximately $346,000 in income from net profits interests. Oil sales represented 88% of total oil and gas sales during the year ended December 31, 2000 as compared to 84% during the year ended December 31, 1999.
The average price for an mcf of gas received by the Partnership increased during the same period by 74%, or $1.59 per mcf, resulting in an increase of approximately $47,900 in income from net profits interests.
The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $393,900. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 4,420 barrels or 13% during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $72,100 in income from net profits interests.
Gas production decreased approximately 19,870 mcf or 40% during the same period, resulting in a decrease of approximately $42,500 in income from net profits interests.
The total decrease in income from net profits interests due to the change in production is approximately $114,600. The Partnership's dramatic decline in gas production was primarily in connection with two wells. During 1999, the Partnership was involved in a lawsuit in order to receive payment for two months of production from the purchaser at that time. The lawsuit was settled in the current year with the Partnership receiving less than was owed from the purchaser. The original accrual recorded during the second quarter of 1999 was reversed in the current year. This reversal represented approximately 2,800 mcf. Additionally, the partnership was informed during the current year that a workover which was performed during the last quarter of 1999 on a non-operated well was not only unsuccessful but caused the well to shut down. This well is not believed to be recoverable, thus the loss to the Partnership is considered to be permanent. This well represented approximately 1,320 mcf a month. Total decline for the partnership during the year ended December 31, 2000 in connection with this non-operated well was approximately 15,700 mcf.
3. Lease operating costs and production taxes were 15% higher, or approximately $72,900 more during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as overhead and pulling expense on two leases, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed the Partnership to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.
Costs and Expenses
Total costs and expenses decreased to $71,195 from $81,876 for the years ended December 31, 2000 and 1999, respectively, a decrease of 13%. The decrease is the result of lower depletion expense and general and administrative costs.
1. General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 4% or approximately $1,700 during the year ended December 31, 2000 as compared to the year ended December 31, 1999.
3. Depletion expense decreased to $31,000 for the year ended December 31, 2000 from $40,000 for the same period in 1999. This represents a decrease of 23%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by the Partnership's independent petroleum consultants.
The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine the Partnership's reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $12,000 as of December 31, 1999.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2001, 2000 and 1999 was $76,865, $318,946 and $99,087, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $182,865, $349,946, $139,087, respectively. Correspondingly, Partnership distributions for the years ended December 31, 2001, 2000 and 1999 were $330,587, $286,050 and $74,277, respectively. The differences are indicative of the changes in oil and gas prices, production and properties.
The source for the 2001 distributions of $330,587 were oil and gas operations of approximately $257,900, with the balance from available cash on hand at the beginning of the period. The source for the 2000 distributions of $286,050 were oil and gas operations of approximately $352,000, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $74,277 were oil and gas operations of approximately $72,300 and the change in oil and gas properties of approximately $18,800, resulting in excess cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2001 were $330,587 of which $297,528 was distributed to the limited partners and $33,059 to the general partners. The per unit distribution to limited partners during the same period was $49.73. Total distributions during the year ended December 31, 2000 were $286,050 of which $257,445 was distributed to the limited partners and $28,605 to the general partners. The per unit distribution to limited partners during the same period was $43.03. Total distributions during the year ended December 31, 1999 were $74,277 of which $68,477 was distributed to the limited partners and $5,800 to the general partners. The per unit distribution to limited partners during the same period was $11.45.
Since inception of the Partnership, cumulative monthly cash distributions of $3,263,832 have been made to the partners. As of December 31, 2001, $2,950,978 or $493.23 per limited partner unit, has been distributed to the limited partners, representing a 99% return of the capital contributed.
Liquidity and Capital Resources The primary source of cash is from operations, the receipt of income from net profits interests in oil and gas properties. The Partnership knows of no material change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $257,900 in 2001 compared to $352,000 in 2000 and approximately $72,300 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.
The Partnership had no cash flows from investing activities in 2001 and 2000. Cash flows provided by investing activities were approximately $18,800.
Cash flows used in financing activities were approximately $330,600 in 2001 compared to $286,100 in 2000 and approximately $74,300 in 1999. The only 2001 use in financing activities was the distributions to partners.
As of December 31, 2001, the Partnership has approximately $51,300 in working capital. The Managing General Partner believes the revenue generated from operations are adequate to meet the operating needs of the Partnership.
Liquidity - Managing General Partner The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.
There can be no assurance that the Managing General Partner's debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner's ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership's name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.
Recent Accounting Pronouncements In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No.133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.
The FASB has issued Statement No. 143 "Accounting for Asset Retirement Obligations" which establishes requirements for the accounting of removal- type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." This pronouncement supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed" and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative instruments.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Independent Auditors Report 19
Balance Sheets 20
Statements of Operations 21
Statement of Changes in Partners' Equity 22
Statements of Cash Flows 23
Notes to Financial Statements 25
INDEPENDENT AUDITORS REPORT
The Partners Southwest Royalties Institutional Income Fund X-C, L.P. (A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund X-C, L.P. (the "Partnership") as of December 31, 2001 and 2000, and the related statements of operations, changes in partners' equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund X-C, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas March 10, 2002
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership) Balance Sheets December 31, 2001 and 2000
2001 2000 ---- ---- Assets ------
Current assets: Cash and cash equivalents $ 15,300 87,960 Receivable from Managing General Partner 35,973 111,036
- --------- --------- Total current assets 51,273 198,996
- --------- --------- Oil and gas properties - using the full- method of accounting 2,221,662 2,221,662 Less accumulated depreciation, depletion and amortization 2,066,479 1,960,479
- --------- --------- Net oil and gas properties 155,183 261,183
- --------- --------- $ 206,456 460,179
========= ========= Liabilities and Partners' Equity --------------------------------
Partners' equity: General partners $ (26,923) (12,149) Limited partners 233,379 472,328
- --------- --------- Total partners' equity 206,456 460,179
- --------- --------- $ 206,456 460,179
========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 2001, 2000 and 1999
2001 2000 1999 ---- ---- ---- Revenues --------
Income from net profits interests $ 220,775 386,562 180,192 Interest from operations 2,745 3,579 771 ------- - ------- --------- 223,520 390,141 180,963 ------- - ------- --------- Expenses --------
General and administrative 40,655 40,195 41,876 Depreciation, depletion and amortization 106,000 31,000 40,000 ------- - ------- --------- 146,655 71,195 81,876 ------- - ------- --------- Net income $ 76,865 318,946 99,087 ======= ======= ========= Net income allocated to:
Managing General Partner $ 16,458 31,496 12,518 ======= ======= ========= General partner $ 1,828 3,499 1,391 ======= ======= ========= Limited partners $ 58,579 283,951 85,178 ======= ======= ========= Per limited partner unit $ 9.79 47.46 14.24 ======= ======= =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 2001, 2000 and 1999
General Limited Partners Partners Total -------- -------- ----- Balance at December 31, 1998 $ (26,648) 429,121 402,473
Net income 13,909 85,178 99,087
Distributions (5,800) (68,477) (74,277) ------- - --------- -------- Balance at December 31, 1999 (18,539) 445,822 427,283
Net income 34,995 283,951 318,946
Distributions (28,605) (257,445)(286,050) ------- - --------- -------- Balance at December 31, 2000 (12,149) 472,328 460,179
Net income 18,286 58,579 76,865
Distributions (33,059) (297,528)(330,587) ------- - --------- -------- Balance at December 31, 2001 $ (26,923) 233,379 206,456 ======= ========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2001, 2000 and 1999
2001 2000 1999 ---- ---- ----
Cash flows from operating activities:
Cash received from net profits interests $ 296,433 389,892 116,032 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (41,251) (41,557)(44,517) Interest received 2,745 3,579 771 ------- - ------- --------- Net cash provided by operating activities 257,927 351,914 72,286 ------- - ------- --------- Cash flows from investing activities:
Sale of oil and gas properties - - 18,762 ------- - ------- --------- Cash flows from financing activities:
Distributions to partners (330,587) (286,052) (74,291) ------- - ------- --------- Net (decrease) increase in cash and equivalents (72,660) 65,862 16,757
Beginning of period 87,960 22,098 5,341 ------- - ------- --------- End of period $ 15,300 87,960 22,098 ======= ======= =========
(continued)
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership) Statements of Cash Flows, continued Years ended December 31, 2001, 2000 and 1999
2001 2000 1999 ---- ---- ----
Reconciliation of net income to net cash provided by operating activities:
Net income $ 76,865 318,946 99,087
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 106,000 31,000 40,000 Decrease (increase) in receivables 75,655 3,330 (64,160) (Decrease) increase in payables (593) (1,362) (2,641) ------- - ------- ------- Net cash provided by operating activities $ 257,927 351,914 72,286 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Royalties Institutional Income Fund X-C, L.P. was organized under the laws of the state of Delaware on September 20, 1991, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to several purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:
Limited General Partners Partners -------- -------- Interest income on capital contributions 100% - Oil and gas sales 90% 10% All other revenues 90% 10% Organization and offering costs (1) 100% - Syndication costs 100% - Amortization of organization costs 100% - Property acquisition costs 100% - Gain/loss on property disposition 90% 10% Operating and administrative costs (2) 90% 10% Depreciation, depletion and amortization of oil and gas properties 100% - All other costs 90% 10%
(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.
(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.
2. Summary of Significant Accounting Policies
Oil and Gas Properties Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.
Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership's independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Oil and Gas Properties - continued Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.
Estimates and Uncertainties 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. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserves estimates, which are inherently imprecise. Actual results could differ from those estimates.
Syndication Costs Syndication costs are accounted for as a reduction of partnership equity.
Environmental Costs The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Gas Balancing The Partnership utilizes the sales method of accounting for gas- balancing arrangements. Under this method, the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.
Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Partnership's tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $448,747 and $386,853 more, respectively, than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Cash and Cash Equivalents For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.
Number of Limited Partner Units As of December 31, 2001, 2000 and 1999 there were 5,983 limited partner units outstanding held by 334, 333 and 336 partners.
Concentrations of Credit Risk The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors' ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.
Recent Accounting Pronouncements In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No.133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.
The FASB has issued Statement No. 143 "Accounting for Asset Retirement Obligations" which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." This pronouncement supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed" and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
3. Liquidity - Managing General Partner The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.
There can be no assurance that the Managing General Partner's debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner's ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership's name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.
4. Commitments and Contingent Liabilities The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one- third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion.
The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.
As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership's properties.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
5. Related Party Transactions A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $183,300, $175,300 and $176,300 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.
Certain subsidiaries or affiliates of the Managing Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $16,200, $15,000 and $4,800 for the years ended December 31, 2001, 2000 and 1999, respectively.
Southwest Royalties, Inc., the Managing General Partner, was paid $36,000 during 2001, 2000 and 1999, for reimbursement of indirect general and administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $36,000 and $111,000 are from oil and gas production, net of lease operating costs and production taxes, as of December 2001 and 2000, respectively.
In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership approximating none for the years ended December 31, 2001, 2000 and 1999.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. Major Customers No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 77% of the Partnership's total oil and gas production during 2001: Teppco Crude Oil LLC for 65% and Plains Marketing LP for 12%. Two purchasers accounted for 84% of the Partnership's total oil and gas production during 2000: Teppco Crude Oil LLC for 72% and Plains Marketing LP for 12%. Two purchasers accounted for 79% of the Partnership's total oil and gas production during 1999: Teppco Crude Oil LLC for 68% and Scurlock Permian LLC for 11%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's sales of oil and gas production.
7. Estimated Oil and Gas Reserves (unaudited) The Partnership's interest in proved oil and gas reserves is as follows:
Oil (bbls) Gas (mcf) ---------- --------- Proved developed and undeveloped reserves -
January 1, 1999 32,000 481,000
Production (35,000) (50,000) Revision of estimates in place 167,000 169,000 ------- --------- December 31, 1999 164,000 600,000
Production (30,000) (30,000) Revision of estimates in place (19,000) (22,000) ------- --------- December 31, 2000 115,000 548,000
Revision of estimates in place (64,000) (111,000) Production (29,000) (44,000) ------- --------- December 31, 2001 22,000 393,000 ======= =========
Proved developed reserves -
December 31, 1999 164,000 563,000 ======= ========= December 31, 2000 115,000 548,000 ======= ========= December 31, 2001 22,000 393,000 ======= =========
All of the Partnership's reserves are located within the continental United States.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued *Ryder Scott Petroleum Engineers prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.
Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.66 per barrel.
Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $1.65 per Mcf.
The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing, proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves.
Because the Partner does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil & Gas Reserves (unaudited) - continued The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:
2001 2000 1999 ---- ---- ---- Future cash inflows, net of production and development costs $ 528,000 4,765,000 2,057,000 10% annual discount for estimated timing of cash flows 209,000 2,324,000 823,000 --------- --------- - --------- Standardized measure of discounted future net cash flows $ 319,000 2,441,000 1,234,000 ========= ========= =========
The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:
2001 2000 1999 ---- ---- ----
Sales of oil and gas produced, net of production costs $ (221,000) (387,000) (180,000) Changes in prices and production costs (2,125,000) 1,833,000 (46,000) Changes of production rates (timing) and others 281,000 (95,000) (22,000) Revisions of previous quantities estimates (301,000) (267,000) 912,000 Accretion of discount 244,000 123,000 52,000 Discounted future net cash flows - Beginning of year 2,441,000 1,234,000 518,000 --------- --------- - --------- End of year $ 319,000 2,441,000 1,234,000 ========= ========= =========
Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.
Southwest Royalties Institutional Income Fund X-C, L.P. (a Delaware limited partnership)
Notes to Financial Statements
8. Selected Quarterly Financial Results - (unaudited)
Quarter ---------------------------------------------- First Second Third Fourth ------ ------- ------ ------ 2001: Total revenues $ 123,389 48,540 40,406 11,185 Total expenses 24,053 31,935 59,225 31,442 Net income (loss) 99,336 16,605 (18,819) (20,257) Net income (loss) per limited partners unit 14.71 2.13 (3.65) (3.40)
2000: Total revenues $ 73,477 88,926 113,653 114,085 Total expenses 21,347 14,246 20,265 15,337 Net income 52,130 74,680 93,388 98,748 Net income per limited partners unit 7.66 11.17 13.88 14.75
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 Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as Managing General Partner. The names, ages, offices, positions and length of service of the directors and executive officers of Southwest Royalties, Inc. are set forth below. Each director and executive officer serves for a term of one year. The present directors of the Managing General Partner have served in their capacity since the Company's formation in 1983.
Name Age Position - -------------------- --- ----------------------------------- - ------- H. H. Wommack, III 46 Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
H. Allen Corey 45 Secretary and Director
Bill E. Coggin 47 Vice President and Chief Financial Officer
J. Steven Person 43 Vice President, Marketing
Paul L. Morris 60 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive Officer, Treasurer, principal stockholder and a director of the Managing General Partner, and has served as its President since the Company's organization in August, 1983. Prior to the formation of the Company, Mr. Wommack was a self-employed independent oil producer engaged in the purchase and sale of royalty and working interests in oil and gas leases, and the drilling of exploratory and developmental oil and gas wells. Mr. Wommack holds a J.D. degree from the University of Texas from which he graduated in 1980, and a B.A. from the University of North Carolina in 1977.
H. Allen Corey, a founder of the Managing General Partner, has served as the Managing General Partner's secretary and a director since its inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew pub restaurant chain based in the Southeast. Prior to his involvement with Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in Chattanooga, Tennessee. He is currently of counsel to the law firm of Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga, Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University Law School and B.A. degree from the University of North Carolina at Chapel Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with the Managing General Partner since 1985. Mr. Coggin was Controller for Rod Ric Corporation of Midland, Texas, an oil and gas drilling company, during the latter part of 1984. He was Controller for C.F. Lawrence & Associates, Inc., an independent oil and gas operator also of Midland, Texas during the early part of 1984. Mr. Coggin taught public school for four years prior to his business experience. Mr. Coggin received a B.S. in Education and a B.B.A. in Accounting from Angelo State University.
J. Steven Person, Vice President, Marketing, assumed his responsibilities with the Managing General Partner as National Marketing Director in 1989. Prior to joining the Managing General Partner, Mr. Person served as Vice President of Marketing for CRI, Inc., and was associated with Capital Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor University in 1982 and an M.B.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings, Inc. since August 1998 and Southwest Royalties, Inc. since September 1998. Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest independently owned oil and gas companies in the United States. Prior to his position with Wagner & Brown, Mr. Morris served as President of Banner Energy and in various managerial positions with the Columbia Gas System, Inc.
Key Employees
Jon P. Tate, Vice President, Land and Assistant Secretary, age 44, assumed his responsibilities with the Managing General Partner in 1989. Prior to joining the Managing General Partner, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as Land Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin Landman's Association and American Association of Petroleum Landmen. Mr. Tate received his B.B.S. degree from Hardin-Simmons University.
R. Douglas Keathley, Vice President, Operations, age 46, assumed his responsibilities with the Managing General Partner as a Production Engineer in October, 1992. Prior to joining the Managing General Partner, Mr. Keathley was employed for four (4) years by ARCO Oil & Gas Company as senior drilling engineer working in all phases of well production (1988- 1992), eight (8) years by Reading & Bates Petroleum Company as senior petroleum engineer responsible for drilling (1980-1988) and two (2) years by Tenneco Oil Company as drilling engineer responsible for all phases of drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum Engineering in 1977 from the University of Oklahoma.
In certain instances, the Managing General Partner will engage professional petroleum consultants and other independent contractors, including engineers and geologists in connection with property acquisitions, geological and geophysical analysis, and reservoir engineering. The Managing General Partner believes that, in addition to its own "in-house" staff, the utilization of such consultants and independent contractors in specific instances and on an "as-needed" basis allows for greater flexibility and greater opportunity to perform its oil and gas activities more economically and effectively.
Item 11.
Item 11. Executive Compensation
The Partnership does not have any directors or executive officers. The executive officers of the Managing General Partner do not receive any cash compensation, bonuses, deferred compensation or compensation pursuant to any type of plan, from the Partnership. The Managing General Partner received $36,000 during 2001, 2000 and 1999 as an administrative fee.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no limited partners who own of record, or are known by the Managing General Partner to beneficially own, more than five percent of the Partnership's limited partnership interests.
The Managing General Partner owns a nine percent interest as a general partner. Through prior purchases the Managing General Partner also owns 104.5 limited partner units, or a 1.8% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 10.6%.
No officer or director of the Managing General Partner owns Units in the Partnership. H. H. Wommack, III, as the individual general partner of the Partnership, owns a one percent interest as a general partner. The officers and directors of the Managing General Partner are considered beneficial owners of the limited partner units acquired by the Managing General Partner by virtue of their status as such. A list of beneficial owners of limited partner units, acquired by the Managing General Partner, is as follows:
Amount and Nature of Percent Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------------- --------------- ------- Limited Partnership Southwest Royalties, Inc. Directly Owns 1.8% Interest Managing General Partner 104.5 Units 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns 1.8% Interest Chairman of the Board, 104.5 Units President, CEO, Treasurer and Director of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. Allen Corey Indirectly Owns 1.8% Interest Secretary and Director of 104.5 Units Southwest Royalties, Inc., the Managing General Partner 633 Chestnut Street Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns 1.8% Interest Vice President and CFO of 104.5 Units Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns 1.8% Interest Vice President, Marketing 104.5 Units of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns 1.8% Interest Director of Southwest 104.5 Units Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
There are no arrangements known to the Managing General Partner which may at a subsequent date result in a change of control of the Partnership.
Item 13.
Item 13. Certain Relationships and Related Transactions
In 2001, the Managing General Partner received $36,000 as an administrative fee. This amount is part of the general and administrative expenses incurred by the Partnership.
In some instances the Managing General Partner and certain officers and employees may be working interest owners in an oil and gas property in which the Partnership also has a net profits interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $183,300 for administrative overhead attributable to operating such properties during 2001.
Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $16,200 for the year ended December 31, 2001.
In the opinion of management, the terms of the above transactions are similar to ones with unaffiliated third parties.
Part IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Independent Auditors Report Balance Sheets Statement of Operations Statement of Changes in Partners' Equity Statement of Cash Flows Notes to Financial Statements
(2) Schedules I through XIII are omitted because they are not applicable, or because the required information is shown in the financial statements or the notes thereto.
(3) Exhibits:
4 (a): Certificate of Limited Partnership of Southwest Royalties Institutional Income Fund X-C, L.P., dated January 28, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(b): Agreement of Limited Partnership of Southwest Royalties Institutional Income Fund X-C, L.P. dated April 28, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(b) Report on Form 8-K
There were no reports filed on Form 8-K during the quarter ended December 31, 2001.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Royalties Institutional Income Fund X-C, L.P., a Delaware limited partnership
By: Southwest Royalties, Inc., Managing General Partner
By: /s/ H. H. Wommack, III ----------------------------- H. H. Wommack, III, President
Date: March 29, 2002
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 Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III ----------------------------------- H. H. Wommack, III, Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
Date: March 29, 2002
By: /s/ H. Allen Corey ----------------------------- H. Allen Corey, Secretary and Director
Date: March 29, 2002