Item 1. Business
General Southwest Royalties, Inc. Income Fund VI (the "Partnership" or "Registrant") was organized as a Tennessee limited partnership on December 4, 1986. The offering of limited partnership interests began August 25, 1986, reached minimum capital requirements on October 3, 1986 and concluded January 29, 1987. The Partnership has no subsidiaries. The Managing General Partner of the Partnership is Southwest Royalties, Inc. (the "Managing General Partner"), a Delaware corporation.
The Partnership has expended its capital and acquired interests in producing oil and gas properties. After such acquisitions, the Partnership has produced and marketed the crude oil and natural gas produced 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 nonoperating interests. The Partnership purchased either all or part of the rights and obligations under various oil and gas leases.
During 2004, the Managing General Partner was acquired by Clayton Williams Energy, Inc. ("CWEI"), a Delaware corporation, and is now a wholly owned subsidiary of CWEI. CWEI is an oil and gas company based in Midland, Texas, and its common stock is traded on the Nasdaq Stock Market's National Market under the symbol "CWEI". All of the directors and executive officers of the Managing General Partner are employees of CWEI. CWEI maintains an internet website at www.claytonwilliams.com from which public information about CWEI may be obtained.
The principal executive offices of the Partnership are located at 6 Desta Drive, Suite 6500, Midland, Texas, 79705. The Managing General Partner and its staff, 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. The Partnership has no employees.
Operations
The business objective of the Partnership is to maximize the production and related net cash flow from the properties it currently owns without engaging in the drilling of any development or exploratory wells except through farm-out arrangements. If additional drilling is necessary to fully develop a Partnership property, the Partnership will enter into a farmout agreement with the Managing General Partner to assign a portion of the Partnership's interest in the property to the Managing General Partner in exchange for retaining an interest in the one or more new wells at no cost to the Partnership. The Managing General Partner obtains a fairness opinion from an unaffiliated petroleum engineer with respect to the terms of each farmout agreement with the Partnership.
During 2005, the Partnership entered into farmout agreements with the Managing General Partner through which the Managing General Partner drilled seven wells and performed workovers on three wells. The partnership paid none of the cost to drill and complete or workover these wells. The wells involved and interest retained are as follows:
Drill Barnett 10% Amacker #4 Drill JS Lane #6 10% Drill Middleton 124 12.5 C #9 % Drill Elizabeth 10% Windham #6 Drill RS Windham #4 10% Drill RS Windham B 10% #2 Drill RS Windham B 10% #3 Workov Mary Shirk #1 30% er Workov Mary Shirk #2 20% er Workov RS Windham #1 10% er
Principal Products and Markets The Partnership has acquired and holds royalty interests and net profit interests in oil and gas properties located in Texas and Oklahoma. All activities of the Partnership are confined to the continental United States. During 2005, 38% of the Partnership's revenues were derived from the sale of oil production and 62% were derived from gas production. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business. The Partnership believes that the loss of any of its purchasers would not have a material adverse affect on its results of operations due to the availability of other purchasers.
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. The Partnership is unable to accurately predict future prices of oil and natural gas.
Competition Because the Partnership has utilized all of its funds available for the acquisition of net profits or royalty 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
The Partnership's oil and gas production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Partnership's cost of doing business and affects the Partnership's profitability. Because such rules and regulations are frequently amended or reinterpreted, the Partnership is unable to predict the future cost or impact of complying with such laws.
All of the states in which the Partnership conducts business generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from the Partnership's properties.
The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas produced by the Partnership, as well as the revenues the Partnership receives for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance the Partnership's ability to market and transport its gas, although this framework may also subject the Partnership to competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
The Partnership's sales of oil production are not presently regulated and are made at market prices. The price the Partnership receives from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. The Partnership is not able to predict with any certainty what effect, if any, these regulations will have on the Partnership, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Environmental Matters
The Partnership's operations pertaining to oil and gas production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to or in connection with drilling activities, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production, restrict or prohibit drilling activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells, and impose substantial liabilities for pollution resulting from the Partnership's operations. Such laws and regulations may substantially increase the cost of developing, producing or processing oil and gas and may prevent or delay the commencement or continuation of a given project and thus generally could have a material adverse effect upon the Partnership's cash flow and earnings. The Partnership believes that it is in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2006. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on the Partnership's operations, as well as the oil and gas industry in general. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as "hazardous wastes," which reclassification would make exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements. State initiatives to further regulate the disposal of oil and gas wastes and naturally occurring radioactive materials, if adopted, could have a similar impact on the Partnership.
The United States Oil Pollution Act of 1990 ("OPA `90"), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA `90 and such similar legislation and related regulations impose on us a variety of obligations related to the prevention of oil spills and liability for damages resulting from such spills. OPA `90 imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil removal costs and a variety of public and private damages.
The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The failure of an operator of a property owned by the Partnership to comply with applicable environmental regulations may, in certain circumstances, be attributed to the Partnership. The Partnership does not believe that it will be required to incur any material expenditures to comply with existing environmental requirements.
The Resource Conservation and Recovery Act ("RCRA"), and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, the Partnership does not expect to experience more burdensome costs than similarly situated companies
State water discharge regulations and federal waste discharge permitting requirements adopted pursuant to the Federal Water Pollution Control Act prohibit or are expected in the future to prohibit the discharge of produced water and sand and some other substances related to the oil and gas industry, into coastal waters. Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and the Partnership does not believe that these costs will have a material adverse impact on its financial condition and operations.
The Partnership maintains insurance against "sudden and accidental" occurrences, which may cover some, but not all, of the environmental risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such costs or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.
Limited partners should be aware that the assessment of liability associated with environmental liabilities is not always correlated to the value of a particular project. Accordingly, liability associated with the environment under local, state, or federal regulations, particularly clean ups under CERCLA, can exceed the value of the Partnership's investment in the associated site. Partnership Employees The Partnership has no employees; however the Managing General Partner and CWEI have 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, the Partnership engages independent consultants such as petroleum engineers and geologists as needed.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2.
Item 2. Properties
As of December 31, 2005, the Partnership possessed an interest in oil and gas properties located in Garvin, Leflore, McClain and Noble Counties of Oklahoma; Brazos, Burleson, Fayette, Lee, Nolan, Pecos, Upton, Ward and Winkler Counties of Texas. These properties consist of various interests in approximately 171 wells and units.
Reserves
The following table sets forth certain information as of December 31, 2005 with respect to the Partnership's estimated proved oil and gas reserves pursuant to SEC guidelines and standardized measure of discounted future net cash flows.
Proved Developed Proved Total ------------------- ------- ------- ------------------- ------- ---- --------- ---- Produci Nonprod Undevel Proved ng ucing oped ------- ------- ------- ------- ------- ------- ------- ---- ----- ---- ---- Oil (Bbls) 149,000 95,000 23,000 267,000 Gas (Mcf) 3,881,00 325,000 915,000 5,121,00 0 0 Total (BOE) 796,000 149,000 176,000 1,121,00
Standardized measure of discounted future net cash $20,599 flows ,000
The following table sets forth certain information as of December 31, 2005 regarding the Partnership's proved oil and gas reserves for certain significant fields.
Proved Reserves ------------------------ ------------------------ -------- Total Percen Oil t of Oil Gas Equiva Total lent Oil (Bbls (Mcf) (BOE) Equiva ) lent ----- ------ ------ ------ ----- ----- ------ ------ --- --- --- 76,00 4,551, 834,00 74.4% Amacker/Wilsh 0 000 0 ire Rhoda Walker 154,0 471,00 233,00 20.8% 00 0 0 Other 37,00 99,000 54,000 4.8% ----- ------ ------ ------ ----- ------ ------ ------ -- -- -- Total 267,0 5,121, 1,121, 100.0% 00 000 000 ===== ====== ====== ====== == = == ==
The estimates of proved reserves at December 31, 2005 and the standardized measure of discounted future net cash flows were derived from a report prepared by Ryder Scott Company, L.P., petroleum consultants. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of the Partnership's proved reserves and the standardized measure of discounted future net cash flows set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and gas prices. The average prices utilized for the purposes of estimating the Partnership's proved reserves and the standardized measure of discounted future net cash flows as of December 31, 2005 were $59.69 per Bbl of oil and natural gas liquids and $10.43 per Mcf of gas, as compared to $42.02 per Bbl of oil and $5.36 per Mcf of gas as of December 31, 2004.
The reserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and standardized measure are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although the Partnership believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
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.
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 2005 through the solicitation of proxies or otherwise.
Part II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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.
Number of Limited Partner Interest Holders As of December 31, 2005 there were 559 holders of limited partner units in the Partnership.
Distributions Pursuant to Article IV, Section 4.01 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 at the sole discretion of the Managing General Partner." During 2005, distributions were made totaling $2,000,000, with $1,800,000 ($90.00 per unit) distributed to the limited partners and $200,000 to the general partner.
Issuer Purchases of Equity Securities After completion of the Partnership's first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner's interest in the Partnership in accordance with the obligations set forth in the partnership agreement. The pricing mechanism used to calculate the repurchase is based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented at the sole discretion of the Managing General Partner. However, the Managing General Partner's obligation to purchase limited partner units under the partnership agreement is limited to an annual expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners. The following table sets forth certain information regarding purchases of limited partnership units by the Managing General Partner during the year of 2005.
Total Number of Units Average Price Period Purchase Paid Per d Unit - ------------- -------- -------- - ------------- -------- -------- -- - -- January 2005 20 $460.54 February 2005 - - March 2005 - - April 2005 - - May 2005 - - June 2005 - - July 2005 826.50 528.15 August 2005 - - September - - October 2005 - November 2005 - - December 2005 - - -------- ------- - --- TOTALS 846.5 $526.55 ===== ======
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 2005, 2004, 2003, 2002 and 2001 should be read in conjunction with the financial statements included in Item 8:
Years ended December 31, 2005 2004 2003 2002 2001 ------ ------ ------ ------ ------ Revenues $ 2,310,70 1,375,0 1,237,7 104,701 964,152 0 40 19
Net income (loss) before cumulative effect of accounting change 2,033,48 1,082,1 904,659 (171,77 571,669 9 68 5)
Net income 2,033,48 1,082,1 1,021,2 358,225 571,669 9 68 96
Partners' share of net income:
General partners 203,349 108,217 102,130 35,822 57,167
Limited partners 1,830,14 973,951 919,166 322,403 514,502
Limited partners' net income (loss) per unit before cumulative effect of accounting 91.51 48.70 40.71 (7.73) 25.73 change
Limited partners' net income per 91.51 48.70 45.96 16.12 25.73 unit
Limited partners' cash distributions per unit 90.00 50.63 33.75 - 50.74
Total assets $ 2,816,45 2,773,7 2,828,4 2,047,1 1,688,4 4 92 12 63 19
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 has fluctuated over the past few years and is expected to decline in later years based on these factors.
Critical Accounting Policies 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 depletion, depreciation, and amortization ("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.
Supplemental Information The following unaudited information is intended to supplement the financial statements included in this Form 10-K with data that is not readily available from those statements.
Year Ended December 31, 2005 2004 2003 ------ ------ -------- ----- Oil production in 21,708 19,991 21,800 barrels Gas production in mcf 262,245 245,548 275,100 Total (BOE) 65,416 60,916 67,650 Average price per barrel $ 56.14 39.43 of oil 29.69 Average price per mcf of $ 7.62 5.90 gas 4.84 Partnership $ 2,000,00 1,125,04 750,091 distributions 0 1 Limited partner $ 1,800,00 1,012,53 675,082 distributions 0 2 Per unit distribution to $ 90.00 50.63 limited partners 33.75 Number of limited 20,000 20,000 20,000 partner units
Operating Results The following discussion compares our results for the year ended December 31, 2005 to the two previous years. All references to 2005, 2004 and 2003 within this section refer to the respective annual periods.
Income from net profits Oil and gas prices continued to climb to record levels compared to the previous two years. Comparing 2005 to 2004, oil and gas sales increased $981,100, of which price variances accounted for a $814,900 increase and production variances accounted for a $166,200 increase. Comparing 2004 to 2003, oil and gas sales increased $256,200, of which price variances accounted for a $453,100 increase and production variances accounted for a $196,900 decrease.
Production in 2005 (on a BOE basis) was 7% higher than 2004 and 3% lower than 2003. We increased our oil and gas production in 2005 due primarily to production from new wells.
In 2005, our realized oil price was 42% higher than 2004 and 89% higher than 2003, while our realized gas price was 29% higher than 2004 and 57% higher than 2003. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. We have very little control over the prices we receive for our production at the wellhead since most of our physical marketing arrangements are market- sensitive.
Oil and gas production costs on a BOE basis decreased from $14.18 per BOE in 2004 and increased from $11.12 per BOE in 2003 to $13.95 per BOE in 2005. Oil and gas production costs per BOE decreased primarily due to increased production from new wells. Oil and gas production costs increased in 2005 over 2004 primarily due to an increase in production tax costs due to higher product prices. It is likely that these factors will continue to contribute to higher production costs in future periods.
Expenses Depletion on a BOE basis decreased 13% from 2004 and 25% from 2003. Comparing 2005 to 2004, depletion expense decreased $7,200, of which rate variances accounted for a $14,700 decrease and production variances accounted for a $7,500 increase. Comparing 2004 to 2003, depletion expense decreased $28,300, of which rate variances accounted for a $15,400 decrease and production variances accounted for a $12,900 decrease. Depletion rates are a function of net capitalized costs and estimated reserve quantities. The rates for 2006 are expected to be similar to the 2005 rates.
General and administrative ("G&A") expenses were 6% lower than 2004 and 5% lower than 2003 due primarily to lower engineering fees and lower annual report printing costs.
Liquidity and Capital Resources Partnership distributions during the year ended December 31, 2005 were $2,000,000, of which $1,800,000 was distributed to the limited partners and $200,000 to the general partners. Cumulative cash distributions of $21,328,986 have been made to the general and limited partners as of December 31, 2005. As of December 31, 2005, $19,211,791 or $960.59 per limited partner unit has been distributed to the limited partners, representing 192% of contributed capital.
Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Cash flow provided by operating activities for 2005 was 110% higher than 2004 due to the combined effects of several drivers. The positive benefits of a 44% increase in oil and gas sales, driven primarily by higher oil and gas prices, were offset in part by increases in production costs. Our only use in financing activities is the distribution to partners which was 78% higher than 2004.
As of December 31, 2005, the Partnership had approximately $624,400 in working capital. The Managing General Partner knows of no unusual contractual commitments. Although the Partnership held many long-lived properties at inception, because of the restrictions on property development imposed by the partnership agreement, the Partnership cannot develop its non-producing properties, if any. Without continued development, the producing reserves continue to deplete. Accordingly, as the Partnership's properties have matured and depleted, the net cash flows from operations for the Partnership has steadily declined, except in periods of substantially increased commodity pricing. Maintenance of properties and administrative expenses for the Partnership are increasing relative to production. As the properties continue to deplete, maintenance of properties and administrative costs as a percentage of production are expected to continue to increase.
Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 153 "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29" ("SFAS 153"). SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Partnership adopted this statement in the third quarter of 2005, and it did not have an effect on the financial statements.
In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC staff's views regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the first quarter of 2005, undiscounted abandonment costs for wells to be drilled in the future to develop proved reserves are included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing depreciation, depletion and amortization ("DD&A"). The implementation of SAB 106 did not have a material impact on our 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
Report of Independent Registered Public Accounting Firm 17
Balance Sheets 18
Statements of Operations 19
Statement of Changes in Partners' Equity 20
Statements of Cash Flows 21
Notes to Financial Statements 23
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners Southwest Royalties, Inc. Income Fund VI (A Tennessee Limited Partnership)
We have audited the accompanying balance sheets of Southwest Royalties, Inc. Income Fund VI (the "Partnership") as of December 31, 2005 and 2004, and the related statements of operations, partners' equity, and cash flows for each of the years in the three-year period ended December 31, 2005. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, Inc. Income Fund VI as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 3 to the financial statements, the Partnership changed its method of accounting for asset retirement obligations as of January 1, 2003.
KPMG LLP Dallas, Texas March 30, 2006
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership) Balance Sheets December 31, 2005 and 2004
2005 2004 ------ ------ Assets - --------- Current assets: Cash and cash equivalents $ 271,508 128,990 Receivable from Managing General 352,550 342,286 Partner Other 522 313 -------- -------- ------ ------ Total current assets 624,580 471,589 -------- -------- ------ ------ Oil and gas properties - using the full- cost method of accounting 8,531,46 8,547,31 7 7 Less accumulated depreciation, depletion and amortization 6,339,59 6,245,11 3 4 -------- -------- ------ ------ Net oil and gas properties 2,191,87 2,302,20 4 3 -------- -------- ------ ------ $ 2,816,45 2,773,79 4 2 ======== ======== Liabilities and Partners' Equity - ------------------------------------- - ---
Current liability - distribution $ 180 - payable -------- -------- ------ ------
Asset retirement obligation 510,646 501,653 -------- -------- ------ ------ Partners' equity (deficit): General partner (623,772 (627,121 ) ) Limited partners 2,929,40 2,899,26 0 0 -------- -------- ------ ------ Total partners' equity 2,305,62 2,272,13 8 9 -------- -------- ------ ------ $ 2,816,45 2,773,79 4 2 ======== ========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership) Statements of Operations Years ended December 31, 2005, 2004 and 2003
2005 2004 2003 ------ ------ ------ Revenues - ------------- Income from net profits $ 2,304,45 1,372,32 1,227,58 interests 6 3 9 Interest income 5,399 1,972 1,178 Other 845 745 8,952 -------- -------- -------- ------ ----- ----- 2,310,70 1,375,04 1,237,71 0 0 9 -------- -------- -------- ------ ----- ----- Expenses - ------------- Depreciation, depletion and 94,479 101,654 130,000 amortization Accretion expense 27,488 26,642 39,008 General and administrative 155,244 164,576 164,052 -------- -------- -------- ------ ----- ----- 277,211 292,872 333,060 -------- -------- -------- ------ ----- ----- Net income before cumulative effect of accounting change 2,033,48 1,082,16 904,659 9 8
Cumulative effect of change in accounting principle - SFAS No. 143 - See - - 116,637 Note 3 -------- -------- -------- ------ ----- ----- Net income $ 2,033,48 1,082,16 1,021,29 9 8 6 ======== ======= ======= Net income allocated to:
Managing General Partner $ 203,349 108,217 102,130 ======== ======= ======= Limited partners $ 1,830,14 973,951 919,166 ======== ======= ======= Per limited partner unit $ 91.51 48.70 before cumulative effect 40.71 Cumulative effects per - - limited partner unit 5.25 -------- -------- -------- ------ ----- ----- Per limited partner unit $ 91.51 48.70 45.96 ======== ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 2005, 2004 and 2003
General Limited Partner Partners Total -------- -------- -------- --- ----- Balance at December $ (649,950 2,693,75 2,043,80 31, 2002 ) 7 7
Net income 102,130 919,166 1,021,29
Distributions (75,009) (675,082 (750,091 ) ) -------- -------- -------- ------ ------ ------ Balance at December (622,829 2,937,84 2,315,01 31, 2003 ) 1 2
Net income 108,217 973,951 1,082,16
Distributions (112,509 (1,012,5 (1,125,0 ) 32) 41) -------- -------- -------- ------ ------ ------ Balance at December (627,121 2,899,26 2,272,13 31, 2004 ) 0 9
Net income 203,349 1,830,14 2,033,48 0 9
Distributions (200,000 (1,800,0 (2,000,0 ) 00) 00) -------- -------- -------- ------ ------ ------ Balance at December $ (623,772 2,929,40 2,305,62 31, 2005 ) 0 8 ======== ======== ========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership) Statements of Cash Flows Years ended December 31, 2005, 2004 and 2003
2005 2004 2003 ------ ------ ------ Cash flows from operating activities:
Cash received from net profits $ 2,291,33 1,180,93 1,124,00 interests 8 6 2 Cash paid for administrative fees and general and administrative overhead (155,244 (164,576 (164,052 ) ) ) Interest received 5,399 1,972 1,178 Other 845 745 8,952 -------- -------- -------- ------ ------ ------ Net cash provided by 2,142,33 1,019,07 970,080 operating activities 8 7 -------- -------- -------- ------ ------ ------ Cash flows from investing activities:
Sale of oil and gas properties - - 306 -------- -------- -------- ------ ------ ------ Cash flows from financing activities:
Distributions to partners (2,000,0 (1,125,0 (750,091 00) 41) ) Increase (decrease) in 180 - (3,356) distributions payable -------- -------- -------- ------ ------ ------ Net cash used in financing (1,999,8 (1,125,0 (753,447 activities 20) 41) ) -------- -------- -------- ------ ------ ------ Net increase (decrease) in 142,518 (105,964 216,939 cash and cash equivalents )
Beginning of year 128,990 234,954 18,015 -------- -------- -------- ------ ------ ------ End of year $ 271,508 128,990 234,954 ======== ======== ======== (continu ed) Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership) Statements of Cash Flows Years ended December 31, 2005, 2004 and 2003
2005 2004 2003 ------ ------ ------ Reconciliation of net income to net cash provided by operating activities: Net income $ 2,033,48 1,082,16 1,021,29 9 8 6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and 94,479 101,654 130,000 amortization Accretion expense 27,488 26,642 39,008 Settlement of ARO for P&A (2,645) (38,389) - wells Cumulative effect of change in - - (116,637 accounting principle ) Increase in receivables (10,473) (152,998 (103,587 ) ) -------- -------- -------- ------ ------ ------ Net cash provided by operating $ 2,142,33 1,019,07 970,080 activities 8 7 ======== ======== ======== Noncash investing and financing activities: Increase in oil and properties - - Adoption of SFAS No. 143 $ - - 616,464 ======== ======== ======== (Decrease) increase in oil and gas properties - SFAS No. 143 $ (15,850) - 422 ======== ======== ========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
1. Organization Southwest Royalties, Inc. Income Fund VI was organized under the laws of the state of Tennessee on December 4, 1986, 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 a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as the Managing General Partner.
Revenues, costs and expenses are allocated as follows:
Limite General d Partne Partner rs s ------ ------- ----- ----- Interest income on capital 100% - contributions Oil and gas sales 90% 10% All other revenues 90% 10% Organization and offering costs (1) 100% - Amortization of organization costs 100% - Property acquisition costs 100% - Gain/loss on property disposition 90% 10% Operating and administrative costs 90% 10% (2) Depreciation, depletion and amortization of oil and gas properties 90% 10% 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.
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, 2005, 2004 and 2003, 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.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Oil and Gas Properties - continued The Partnership recognizes income from its net profits interest in oil and gas property on an accrual basis, while the quarterly cash distributions of the net profits interest are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. If the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due to the Partnership's net profits interest until the deficit is recovered from future net profits. The Partnership accrues a quarterly loss on its net profits interest provided there is a cumulative net amount due for accrued revenue as of the balance sheet date. As of December 31, 2005, there were no timing differences which resulted in a deficit net profit interest.
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 Partnership's depletion calculation and full cost ceiling test for oil and gas properties uses oil and gas reserve 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.
Revenue Recognition The Partnership recognizes oil and gas sales when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or transport vehicle.
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, 2005 and 2004, the Partnership was under produced by 5,312 and 5,306 mcf of gas, respectively.
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, 2005 and 2004 is $1,880,677 and $1,932,696, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Cash and Cash Equivalents For purposes of the statements 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, 2005, 2004 and 2003, there were 20,000 limited partner units outstanding held by 559, 602 and 667 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 per limited partnership unit The net income per limited partnership unit is calculated by using the number of outstanding limited partnership units.
Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 153 "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29" ("SFAS 153"). SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Partnership adopted this statement in the third quarter of 2005, and it did not have an effect on the financial statements.
In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC staff's views regarding SFAS No. 143 and its impact on both the full- cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the first quarter of 2005, undiscounted abandonment costs for wells to be drilled in the future to develop proved reserves are included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing depreciation, depletion and amortization ("DD&A"). The implementation of SAB 106 did not have a material impact on our financial statements.
3. Asset Retirement Obligations On January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). The standard requires the Partnership to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset and depreciate the additional cost over the estimated useful life of the asset. On January 1, 2003, the Partnership recorded additional costs, net of accumulated depreciation, of $616,464, a long term liability of $499,827 and a gain of $116,637 for the cumulative effect on depreciation of the additional costs and accretion expense on the liability related to expected abandonment costs of its oil and natural gas producing properties.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
3. Asset Retirement Obligation - continued
Changes in abandonment obligations for 2005 and 2004 are as follows:
2005 2004 ------- ------- Beginning of year $ 501,653 513,400 Additional abandonment obligations 3,934 - from new wells Reduction of obligations due to (32,811 - farmouts ) Reduction of obligations due to (2,645) (38,389 wells plugged and abandoned ) Accretion expense 27,488 26,642 Revisions of previous estimates 13,027 - ------- ------- ------- ----- End of year $ 510,646 501,653 ======= ======= =
4. Commitments and Contingent Liabilities After completion of the Partnership's first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner's interest in the Partnership. The pricing mechanism used to calculate the repurchase is based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one- third which may be implemented at the sole discretion of the Managing General Partner. However, the Managing General Partner's obligation to purchase limited partner units is limited to an annual expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.
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, 2005, 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 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 the Partnership's properties.
5. Related Party Transactions A significant portion of the oil and gas properties in which the Partnership has an interest are purchased from and operated by 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 $92,700, $85,700 and $83,000, for the years ended December 31, 2005, 2004 and 2003, respectively. The amounts for administrative overhead attributable to operating the partnerships properties has been deducted from gross oil and gas revenues in the determination of net profit interest. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties in which the Partnership also participates.
Southwest Royalties, Inc., the Managing General Partner, was paid $144,000 during 2005, 2004 and 2003, as an administrative fee for indirect general and administrative overhead expenses. The administrative fees are included in general and administrative expense on the statement of operations.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
5. Related Party Transactions - continued Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $352,600 and $342,300 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2005 and 2004, respectively.
6. Oil and Gas Reserves Information (unaudited) The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under economic and operating conditions existing at the registrant's year end with no provision for price and cost escalations except by contractual arrangements. Future cash inflows were computed by applying year-end prices to the year-end quantities of proved reserves. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing, producing, and abandoning proved oil and gas reserves at the end of the year, based on year-end costs. All of the Partnership's reserves are located in the United States. For information about the Partnership's results of operations from oil and gas producing activities, see the accompanying statements of operations.
The Partnership's interest in proved oil and gas reserves is as follows:
Oil Gas (bbls) (mcf) -------- -------- ---- ----- Total Proved -
January 1, 2003 198,000 4,408,00
Sales of reserves in (3,000) (13,000) place Revisions of previous 12,000 1,129,00 estimates 0 Production (22,000) (275,000 ) -------- -------- ---- ------ December 31, 2003 185,000 5,249,00
New discoveries and 83,000 678,000 extensions Revisions of previous 23,000 200,000 estimates Production (20,000) (246,000 ) -------- -------- ---- ------ December 31, 2004 271,000 5,881,00
New discoveries and 2,000 15,000 extensions Revisions of previous 16,000 (513,000 estimates ) Production (22,000) (262,000 ) -------- -------- ---- ------ December 31, 2005 267,000 5,121,00 ======= ======== Proved developed reserves - December 31, 2003 138,000 4,018,00 ======= ======== December 31, 2004 227,000 4,326,00 ======= ======== December 31, 2005 243,000 4,206,00 ======= ========
Net revisions of 70,000 BOE in 2005 consisted of approximately 44,000 BOE of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, net of downward revisions of approximately 114,000 BOE attributable to well performance primarily from properties in the Amacker/Wilshire field of West Texas.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
6. Oil and Gas Reserves Information (unaudited) - continued Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The standardized measure as of December 31, 2005, 2004 and 2003 reflects an average oil price of $59.69, $42.02 and $31.26 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 standardized measure as of December 31, 2005, 2004 and 2003 reflects an average natural gas price of $10.43, $5.36 and $5.31 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.
The Partnership has reserves, which are classified as proved developed and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate the Partnership's present reserves.
Because the Partnership 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.
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
6. Oil and Gas Reserves Information (unaudited) - continued The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2005, 2004 and 2003 is presented below:
2005 2004 2003 ------ ------ ------ Future cash inflows $ 69,358,0 42,902,0 33,658,0 00 00 00 Production, development and abandonment 18,482,0 12,108,0 8,608,00 costs 00 00 0 -------- -------- -------- ------ ------ ------ Future net cash flows 50,876,0 30,794,0 25,050,0 00 00 00 10% annual discount for estimated timing of 30,277,0 16,769,0 13,629,0 cash flows 00 00 00 -------- -------- -------- ------ ----- ------ Standardized measure of discounted future net cash flows $ 20,599,0 14,025,0 11,421,0 00 00 00 ======== ======== ========
Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2005, 2004 and 2003 are as follows:
2005 2004 2003 ---- ---- ---- Sales of oil and gas produced, net of production $ (2,304,0 (1,372,0 (1,228,0 costs 00) 00) 00) Extensions and 118,000 2,799,00 - discoveries 0 Changes in prices and production costs 10,253,0 185,000 1,679,00 00 0 Changes of production rates (timing) and others (1,618,0 (766,000 (151,000 00) ) ) Sales of minerals in - - (18,000) place Revisions of previous quantities estimates (1,278,0 616,000 2,148,00 00) 0 Accretion of discount 1,403,00 1,142,00 817,000 0 0 Discounted future net cash flows - Beginning of year 14,025,0 11,421,0 8,174,00 00 00 0 -------- -------- -------- ------ ------ ------ End of year $ 20,599,0 14,025,0 11,421,0 00 00 00 ======== ======== ========
Southwest Royalties, Inc. Income Fund VI (a Tennessee limited partnership)
Notes to Financial Statements
7. Selected Quarterly Financial Results - (unaudited)
Quarter -------------------------------------- -------------------------------------- - First Second Third Fourth ------ -------- ------- -------- --- - 2005: Total revenues $ 567,129 533,681 655,046 554,844 Total expenses 71,773 72,428 63,457 69,553 -------- -------- -------- -------- ---- ---- ---- ---- Net income 495,356 461,253 591,589 485,291 ======= ======= ======= =======
Net income per limited $ 22.29 partner unit 20.76 26.62 21.84 ======= ======= ======= =======
Quarter -------------------------------------- -------------------------------------- - First Second Third Fourth ------ -------- ------- -------- --- - 2004: Total revenues $ 381,937 315,017 289,185 388,901 Total expenses 77,552 82,870 76,278 56,172 -------- -------- -------- -------- ---- ---- ---- ---- Net income 304,385 232,147 212,907 332,729 ======= ======= ======= =======
Net income per limited $ 13.70 partner unit 10.45 9.58 14.97 ======= ======= ======= =======
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
The Managing General Partner has established disclosure controls and procedures that are adequate to provide reasonable assurance that management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in the Partnership's reports to the SEC. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and is accumulated and communicated to management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.
With respect to these disclosure controls and procedures:
management has evaluated the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report;
this evaluation was conducted under the supervision and with the participation of management, including the chief executive and chief financial officers of the Managing General Partner; and
it is the conclusion of chief executive and chief financial officers of the Managing General Partner that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Partnership in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.
Internal Control Over Financial Reporting There has not been any change in the Partnership's internal control over financial reporting that occurred during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Item 9B.
Item 9B. Other Information
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. Since the Managing General Partner is a wholly owned subsidiary of CWEI, the directors of the Managing General Partner are elected by management of CWEI. Each director the Managing General Partner serves for a term of one year. Following is certain information concerning each of the directors and executive officers of the Managing General Partner.
CLAYTON W. WILLIAMS, age 74, is Chairman of the Board and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Williams also serves as Chairman of the Board, President, Chief Executive Officer and a director of CWEI.
L. PAUL LATHAM, age 54, is President, Chief Executive Officer and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Latham also serves as Executive Vice President, Chief Operating Officer and a director of CWEI.
MEL G. RIGGS, age 51, is Vice President, Chief Financial Officer, Treasurer and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Riggs also serves as Senior Vice President and Chief Financial Officer of CWEI.
RANDY HOWARD, age 50, is Vice President - of the Managing General Partner, having served in this capacity since March 2006.
ROBERT C. LYON, age 69, is Vice President - Gas Gathering and Marketing of the Managing General Partner, having served in this capacity since May 2004. Mr. Lyon also serves as Vice President - Gas Gathering and Marketing of CWEI.
T. MARK TISDALE, age 49, is Vice President and Secretary of the Managing General Partner, having served in this capacity since May 2004. Mr. Tisdale also serves as Vice President and General Counsel of CWEI.
Code of Ethics
As a wholly owned subsidiary of CWEI, the Managing General Partner is subject to a Code of Conduct and Ethics ("Code") that applies to all directors, executive officers and employees of CWEI and the Managing General Partner. This Code assists employees in complying with the law, in resolving ethical issues that may arise, and in complying with policies established by CWEI. This Code is also designed to promote, among other things, ethical handling of actual or apparent conflicts of interest; full, fair, accurate and timely disclosure in filings with the SEC; compliance with law; and prompt internal reporting of violations of the Code. This Code is available on the website of CWEI at www.claytonwilliams.com under "Investor Relations/Documents".
Item 11.
Item 11. Executive Compensation
The Partnership does not employ any directors, executive officers or employees. The Managing General Partner receives an administrative fee for the management of the Partnership. The Managing General Partner received $144,000 during 2005, 2004 and 2003 as an annual administrative fee. The executive officers of the Managing General Partner do not receive any form of compensation, from the Partnership; instead, their compensation is paid solely by Southwest. The executive officers, however, may occasionally perform administrative duties for the Partnership but receive no additional compensation for this work.
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, other than the Managing General Partner.
Through repurchase offers to the limited partners, the Managing General Partner owns 9,118.4 limited partner units, a 41.0% limited partner interest. The Managing General Partner's total percentage interest ownership in the Partnership is 51.0%.
No officer or director of the Managing General Partner directly owns units in the Partnership. CWEI is considered to be a beneficial owner of the limited partner units acquired by the Managing General Partner by virtue of its ownership of the Managing General Partner. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and includes voting or investment power with respect to the limited partner units.
Item 13.
Item 13. Certain Relationships and Related Transactions
In 2005, the Managing General Partner received $144,000 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 its affiliates 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 $92,700 for administrative overhead attributable to operating such properties during 2005.
The terms of the above transactions are similar to ones, which would have been obtained through arm's length negotiations with unaffiliated third parties.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table presents fees for professional audit services rendered by KPMG LLP for the audit of the Partnership's annual financial statements for the years ended December 31, 2005 and 2004 and fees billed for other services rendered by KPMG during those periods.
For the Year Ended December 2005 2004 31, ------ ------ Audit Fees $13,303 $ 12,865 Audit Related Fees - - Tax Fees - - All Other Fees - - ------ ------ --- -- TOTAL $13,303 $ 12,865 ===== =====
The Audit Committee of CWEI reviewed and approved, in advance, all audit and non-audit services provided by KPMG LLP.
Part IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements:
Included in Part II of this report --
Report of Independent Registered Public Accounting Firm Balance Sheets Statements of Operations Statement of Changes in Partners' Equity Statements of Cash Flows Notes to Financial Statements
(2) Schedules required by Article 12 of Regulation S- X are either 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 and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated December 4, 1986. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1986.)
(b) First Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated January 16,1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(c) Corrected Second Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated May 6, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(d) Third Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated February 3, 1988 (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
(e) Fourth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated June 30, 1988 (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
(f) Fifth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated December 30, 1988 (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
(g) Sixth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of March 19, 1990. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1990.)
(h) Seventh Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of December 31, 1990. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1990.)
(i) Eighth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of September 30, 1991. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1991.)
(j) Ninth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of December 31, 1991. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1992.)
(k) Tenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of March 31, 1992. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1992.)
(l) Eleventh Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of June 30, 1992. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1992.)
(m) Twelfth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of November 23, 1992. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1992.)
(n) Thirteenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of April 22, 1993. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1993.)
(o) Fourteenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of September 30, 1993. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1993.)
(p) Fifteenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of December 31, 1993. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1993.)
(q) Sixteenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of July 26, 1994. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1994.)
(r) Seventeenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of January 18, 1995. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1994.)
(s) Eighteenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of July 26, 1995.
(t) Nineteenth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of January 29, 1996.
(u) Twentieth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of April 30, 1996.
(v) Twenty First Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of September 30, 1996.
(w) Twenty Second Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of January 15, 1997.
(x) Twenty Third Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of May 10, 1997.
(y) Twenty Fourth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of January 30, 1998.
(z) Twenty Fifth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of July 27, 1998.
(aa) Twenty Sixth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of December 22, 1998.
(bb) Twenty Seventh Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of February 25, 1999.
(cc) Twenty Eighth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of July 27, 1999.
(dd) Twenty Ninth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of February 10, 2000.
(ee) Thirtieth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of April 26, 2000.
(ff) Thirty First Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of September 13, 2000.
(gg) Thirty Second Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of February 20, 2001.
(hh) Thirty Third Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of July 16, 2001.
(ii) Thirty Fourth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of January 11, 2002.
(jj) Thirty Fifth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of June 3, 2002.
(kk) Thirty Sixth Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of July 30, 2002.
(ll) Thirty Seventh Amendment to Certificate and Agreement of Limited Partnership of Southwest Royalties, Inc. Income Fund VI, dated as of February 20, 2003.
31.1 Rule 13a-14(a)/15d-14(a) Certification 31.2 Rule 13a-14(a)/15d-14(a) Certification 32.1 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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, Inc. Income Fund VI, a Tennessee limited partnership
By: Southwest Royalties, Inc., Managing General Partner
By: /s/ L. Paul Latham L. Paul Latham President and Chief Executive Officer
Date: March 30, 2006
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ Clayton W Williams /s/ L. Paul Latham Clayton W. Williams, L. Paul Latham, Chairman of the Board President and a Director and a Director
Date: March 30, 2006 Date: March 30, 2006
/s/ Mel G. Riggs Mel G. Riggs, Vice President - Finance, Treasurer and a Director
Date: March 30, 2006
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Royalties, Inc. Income Fund VI
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 30, 2006 /s/ L. Paul Latham L. Paul Latham President and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Royalties, Inc. Income Fund VI
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Royalties, Inc. Income Fund VI
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 30, 2006 /s/ Mel G. Riggs Mel G. Riggs Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Royalties, Inc. Income Fund VI
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
Pursuant to 18 U.S.C. 1350 and in connection with the accompanying report on Form 10-K for the period ended December 31, 2005 that is being filed concurrently with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned officers of Southwest Royalties, Inc. Income Fund VI (the "Company"), hereby certifies that:
1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.
/s/ L. Paul Latham L. Paul Latham President and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Royalties, Inc. Income Fund VI
March 30, 2006
/s/ Mel G. Riggs Mel G. Riggs Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Royalties, Inc. Income Fund VI
March 30, 2006