Item 1. Business
General Southwest Oil & Gas Income Fund IX-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on March 9, 1989. The offering of limited partnership interests began May 11, 1989, reached minimum capital requirements on October 25, 1989 and concluded March 31, 1990. The Partnership has no subsidiaries.
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 working interests in oil and gas properties, with an occasional purchase of a royalty or overriding royalty interest. 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 82 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, Chairman, Director, President and Chief Executive Officer 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 working interests in oil and gas properties located in Texas and New Mexico. 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.
In 2002, fighting and threats of fighting in the Middle East and a strike in a major oil exporting country dominated the direction of crude oil prices. While OPEC agreed to keep production constant throughout the year, conflicts between the U.S. and Iraq, as well as between Israel and the Palestinians threatened supplies and caused oil prices to surge in 2002. In addition, a strike by oil workers in Venezuela, the fourth largest supplier to the U.S., took a significant amount of crude oil off the market toward the end of the year. As a result, OPEC agreed in January 2003 to increase output by 1.5 million barrels per day in an effort to make up for the lost supply and stabilize prices.
In 2002, spot prices for natural gas fell by 27.5% from the unprecedented heights reached in 2001, averaging just under $3.00/MMBtu for the year. Most of the lowest prices were seen early on, with the first quarter averaging of $2.24/MMBtu. But as the year progressed, prices climbed higher, ending with a $3.99 average in December. As for 2003, industry analysts are divided on their gas price predictions, with estimates ranging anywhere from $4.00 to $6.00/MMBtu. Weather forecasts, storage inventory levels, a tighter supply and demand balance, and the unstable situation with Iraq are all factors that will have a significant impact on the direction prices will take. Overall however, analysts are maintaining a bullish perspective, expecting gas prices to remain at or above $4.00/MMBtu in 2003.
Following is a table of the ratios of revenues received from oil and gas production for the last three years:
Oil Gas ----- ------ 2002 65% 35% 2001 59% 41% 2000 60% 40%
As the table indicates, the Partnership's revenue is becoming higher in its oil production; the Partnership revenues will be highly dependent upon the future prices and demands for oil and gas.
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. Three purchasers accounted for 79% of the Partnership's total oil and gas production during 2002: Phillips 66 Company for 49%, Duke Energy Field Services LP for 16% and Plains Marketing LP for14%. Three purchasers accounted for 71% of the Partnership's total oil and gas production during 2001: Phillips 66 Company for 45%, Duke Energy Field Services for 14% and Plains Marketing LP for 12%. Two purchasers accounted for 77% of the Partnership's total oil and gas production during 2000: Phillips 66 Company for 64%, and Plains Marketing LP for 13%.
All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event any 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, 2002, there were 82 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, 2002, the Partnership possessed an interest in oil and gas properties located in Eddy and Lea Counties of New Mexico; Andrews, Crane, Ector, Garza, Howard, Martin, Pecos, Stonewall, Ward and Winkler Counties of Texas. These properties consist of various interests in approximately 188 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 2002, 2001 and 2000.
During 2002, one lease was sold for approximately $3,400. There were no property sales during 2001 and 2000.
Significant Properties The following table reflects the significant properties in which the Partnership has an interest:
Date Purchased No. of Proved Reserves* Name and and Interest Wells Oil Gas Location (bbls) (mcf) - ---------------- ------------- ------ -------- -------- - ---------- ---- --- ----- ----- Phillips/Odessa 1/90 at 13% 45 187,000 723,000 Properties, to 52% 12 counties in working interest Texas, 2 counties in New Mexico
*Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2003. 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, 2003 are an average price of $29.28 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, 2003 are an average price of $4.30 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 2002.
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 developed non-producing 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, 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 2002 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. As of December 31, 2002, no limited partner units were purchased by the Managing General Partner. Southwest, as Managing General Partner, evaluated several liquidity alternatives for the partnerships in 2001 and 2002. During 2002, Southwest specifically pursued the possible roll-up and merger of twenty- one (21) partnerships with the general partner. Because of the complexities and conflicts of interest in such a transaction, the Managing General Partner did not make a formal repurchase offer in 2002 but has responded to limited partners desiring to sell their units in the partnerships on an "as requested" basis. Southwest anticipates that it will maintain this policy in 2003 because the aforementioned transaction is ongoing. In 2001, 40 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $161.10 per unit. In 2000, 120.5 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $74.58 per unit.
Number of Limited Partner Interest Holders As of December 31, 2002, there were 562 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 in the sole discretion of the Managing General Partner."
During 2002, quarterly distributions were made totaling $218,523, with $196,671 distributed to the limited partners and $21,852 to the general partners. For the year ended December 31, 2002, distributions of $18.81 per limited partner unit were made, based upon 10,453 limited partner units outstanding. During 2001, quarterly distributions were made totaling $646,169, with $581,552 distributed to the limited partners and $64,617 to the general partners. For the year ended December 31, 2001, distributions of $55.63 per limited partner unit were made, based upon 10,453 limited partner units outstanding. During 2000, quarterly distributions were made totaling $615,794, with $564,502 distributed to the limited partners and $51,292 to the general partners. For the year ended December 31, 2000, distributions of $54.00 per limited partner unit were made, based upon 10,453 limited partner units outstanding.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 2002, 2001, 2000, 1999 and 1998 should be read in conjunction with the financial statements included in Item 8:
Years ended December 31, ------------------------------------------------ --------- 2002 2001 2000 1999 1998 ------ ------ ------ ------ ------ Revenues $ 832,356 1,014,35 1,217,37 734,701 707,744 6 3
Net income 261,294 401,609 658,754 237,535 6,584
Partners' share of net income (loss):
General partners 28,629 45,461 67,876 26,553 12,559
Limited partners 232,665 356,148 590,878 210,982 (5,975)
Limited partners' net income (loss) per unit 22.26 34.07 56.53 20.18 (.57)
Limited partners' cash distributions per unit 18.81 55.63 54.00 22.79 23.43
Total assets $ 470,165 427,412 671,235 628,402 653,559
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General The Partnership was formed to acquire 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 couple of years and is expected to fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing drilling projects and workovers during the years 2003 and 2004 to enhance production. The partnership may have an increase in production volumes for the years 2003 and 2004, otherwise, the partnership will most likely experience the historical production decline, which have approximated 8% 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.
Prior to October 1, 2002, the Partnership calculated depletion of oil and gas properties under the units of revenue method. The Partnership changed methods of estimating depletion effective October 1, 2002 to the units of production method. The units of production method is more predominantly used throughout the oil and gas industry and will allow the Partnership to more closely align itself with its peers. The effect of this change in estimate was to increase 2002 depletion expense by $1,000 and decrease 2002 net income by $1,000.
Results of Operations
A. General Comparison of the Years Ended December 31, 2002 and 2001
The following table provides certain information regarding performance factors for the years ended December 31, 2002 and 2001:
Year Ended Percenta ge December 31, Increase 2002 2001 (Decreas e) ------ ------ -------- ------- Average price per $ 24.30 23.54 3% barrel of oil Average price per mcf $ 2.58 3.39 (24%) of gas Oil production in 22,100 25,400 (13%) barrels Gas production in mcf 110,800 121,600 (9%) Gross oil and gas $ 822,546 1,009,78 (19%) revenue 4 Net oil and gas revenue $ 356,228 529,801 (33%) Partnership $ 218,523 646,169 (66%) distributions Limited partner $ 196,671 581,552 (66%) distributions Per unit distribution $ 18.81 55.63 (66%) to limited partners Number of limited 10,453 10,453 partner units
Revenues
The Partnership's oil and gas revenues decreased to $822,546 from $1,009,784 for the years ended December 31, 2002 and 2001, respectively, a decrease of 19%. The principal factors affecting the comparison of the years ended December 31, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2002 as compared to the year ended December 31, 2001 by 3%, or $.76 per barrel, resulting in an increase of approximately $16,800 in revenues. Oil sales represented 65% of total oil and gas sales during the year ended December 31, 2002 as compared to 59% during the year ended December 31, 2001.
The average price for an mcf of gas received by the Partnership decreased during the same period by 24%, or $.81 per mcf, resulting in a decrease of approximately $89,700 in revenues.
The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $72,900. 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 3,300 barrels or 13% during the year ended December 31, 2002 as compared to the year ended December 31, 2001, resulting in a decrease of approximately $77,700 in revenues.
Gas production decreased approximately 10,800 mcf or 9% during the same period, resulting in a decrease of approximately $36,600 in revenues.
The total decrease in revenues due to the change in production is approximately $114,300.
Costs and Expenses
Total costs and expenses decreased to $571,062 from $612,747 for the years ended December 31, 2002 and 2001, respectively, a decrease of 7%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative costs.
1. Lease operating costs and production taxes were 3% lower, or approximately $13,700 less during the year ended December 31, 2002 as compared to the year ended December 31, 2001.
2. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased less than 1% or approximately $20 during the year ended December 31, 2002 as compared to the year ended December 31, 2001.
3. Depletion expense decreased to $25,000 for the year ended December 31, 2002 from $53,000 for the same period in 2001. This represents a decrease of 53%. Prior to October 1, 2002, the Partnership calculated depletion of oil and gas properties under the units of revenue method. The Partnership changed methods of estimating depletion effective October 1, 2002 to the units of production method. The units of production method is more predominantly used throughout the oil and gas industry and will allow the Partnership to more closely align itself with its peers. The effect of this change in estimate was to increase 2002 depletion expense by $1,000 and decrease 2002 net income by $1,000.
The major factor in the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by the Partnership during 2002 as compared to 2001.
Results of Operations
B. 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 Percenta ge December 31, Increase 2001 2000 (Decreas e) ------ ------ -------- ----- Average price per $ 23.54 (19%) barrel of oil 29.05 Average price per $ 3.39 (2%) mcf of gas 3.47 Oil production in 25,400 25,000 2% barrels Gas production in 121,600 138,800 (12%) mcf Gross oil and gas $ 1,009,78 1,208,57 (16%) revenue 4 5 Net oil and gas $ 529,801 747,853 (29%) revenue Partnership $ 646,169 615,794 5% distributions Limited partner $ 581,552 564,502 3% distributions Per unit $ 55.63 3% distribution to 54.00 limited partners Number of limited 10,453 10,453 partner units
Revenues
The Partnership's oil and gas revenues decreased to $1,009,784 from $1,208,575 for the years ended December 31, 2001 and 2000, respectively, a decrease of 16%. 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 19%, or $5.51 per barrel, resulting in a decrease of approximately $140,000 in revenues. Oil sales represented 59% of total oil and gas sales during the year ended December 31, 2001 as compared to 60% during the year ended December 31, 2000.
The average price for an mcf of gas received by the Partnership decreased during the same period by 2%, or $.08 per mcf, resulting in a decrease of approximately $9,700 in revenues.
The total decrease in revenues due to the change in prices received from oil and gas production is approximately $149,700. 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 increased approximately 400 barrels or 2% during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in an increase of approximately $11,600 in revenues.
Gas production decreased approximately 17,200 mcf or 12% during the same period, resulting in a decrease of approximately $59,700 in revenues.
The net total decrease in revenues due to the change in production is approximately $48,100.
Costs and Expenses
Total costs and expenses increased to $612,747 from $558,619 for the years ended December 31, 2001 and 2000, respectively, an increase of 10%. The increase is the result of higher lease operating costs, depletion expense and general and administrative costs.
1. Lease operating costs and production taxes were 4% higher, or approximately $19,300 more during the year ended December 31, 2001 as compared to the year ended December 31, 2000.
2. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs increased 2% or approximately $1,900 during the year ended December 31, 2001 as compared to the year ended December 31, 2000.
3. Depletion expense increased to $53,000 for the year ended December 31, 2001 from $20,000 for the same period in 2000. This represents an increase of 165%. 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 in 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 $23,000 as of December 31, 2000.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2002, 2001 and 2000 was $261,294, $401,609 and $658,754, respectively. Excluding the effects of depreciation, depletion and amortization, net income would have been $286,294 in 2002, $454,609 in 2001 and $678,754 in 2000. Correspondingly, Partnership distributions for the years ended December 31, 2002, 2001 and 2000 were $218,523, $646,169 and $615,794, respectively. These changes are indicative of the changes in oil and gas prices, production and properties during 2002, 2001 and 2000.
The sources for the 2002 distributions of $218,523 were oil and gas operations of approximately $244,200 and the change in oil and gas properties $5,600, resulting in excess cash for contingencies or subsequent distributions. The sources for the 2001 distributions of $646,169 were oil and gas operations of approximately $523,300 and the change in oil and gas properties of approximately $(5,600), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $615,794 were oil and gas operations of approximately $659,300 and the change in oil and gas properties of approximately $(31,000), resulting in excess cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2002 were $218,523 of which $196,671 was distributed to the limited partners and $21,852 to the general partners. The per unit distribution to limited partners during the same period was $18.81. Total distributions during the year ended December 31, 2001 were $646,169 of which $581,552 was distributed to the limited partners and $64,617 to the general partners. The per unit distribution to limited partners during the same period was $55.63. Total distributions during the year ended December 31, 2000 were $615,794 of which $564,502 was distributed to the limited partners and $51,292 to the general partners. The per unit distribution to limited partners during the same period was $54.00.
Since inception of the Partnership, cumulative monthly cash distributions of $7,659,450 have been made to the partners. As of December 31, 2002, $6,962,371 or $666.06 per limited partner unit, has been distributed to the limited partners, representing a 100% return of capital and a 33% return on capital contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from 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 $244,200 in 2002 compared to $523,300 in 2001 and approximately $659,300 in 2000. The primary source of the 2002 cash flow from operating activities was profitable operations.
Cash flows provided by (used in) investing activities were approximately $5,600 in 2002 compared to $(5,600) in 2001 and approximately $(31,000) in 2000. The principal source of the 2002 cash flow from investing activities was the sale of oil and gas properties.
Cash flows used in financing activities were approximately $218,500 in 2002, $645,400 in 2001 and approximately $615,900 in 2000. The only use in financing activities was the distributions to partners.
As of December 31, 2002, the Partnership had approximately $160,800 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 Managing General Partner anticipates that at some point in the near future, the partnership will need to be liquidated. Maintenance of properties and administrative expenses are increasing relative to production. As the properties continue to deplete, maintenance of properties and administrative costs as a percentage of production will continue to increase.
As the partnerships properties have matured, the net cash flows from operations for the partnership have generally declined, except in periods of substantially increased commodity pricing. Since the partnership cannot develop their non-producing properties, the producing reserves continue to deplete causing cash flow to steadily decline.
On October 17, 2002, Southwest Royalties, Inc. the Managing General Partner filed an S-4 "Registration of Securities, Business Combinations" with the Securities and Exchange Commission. The S-4 relates to a proposed plan of merger of twenty-one limited partnerships.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with approximately $124.0 million of principal due between December 31, 2002 and December 31, 2004. The Managing General Partner is constantly monitoring its cash position and its ability to meet its financial obligations as they become due, and in this effort, is continually exploring various strategies for addressing its current and future liquidity needs. The Managing General Partner regularly pursues and evaluates recapitalization strategies and acquisition opportunities (including opportunities to engage in mergers, consolidations or other business combinations) and at any given time may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from operations, the Managing General Partner has adequate cash flow to fund debt service, developmental projects and day to day operations, but it is not sufficient to build a cash balance which would allow the Managing General Partner to meet its debt principal maturities scheduled for 2004. Therefore the Managing General Partner must renegotiate the terms of its various obligations or seek new lenders or equity investors in order to meet its financial obligations, specifically those maturing in 2004. The Managing General Partner may be required to dispose 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 debt holders will agree to a course of action consistent with the Managing General Partner's requirements in restructurings the obligations. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner.
Recent Accounting Pronouncements 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.
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 24
INDEPENDENT AUDITORS REPORT
The Partners Southwest Oil & Gas Income Fund IX-A, L.P. (A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund IX-A, L.P. (the "Partnership") as of December 31, 2002 and 2001, 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, 2002. 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 Oil & Gas Income Fund IX-A, L.P. as of December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas March 14, 2003
Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 2002 and 2001
2002 2001 ------ ------
Assets - ----------
Current assets: Cash and cash equivalents $ 69,506 38,153 Receivable from Managing 91,980 49,932 General Partner -------- -------- ----- ----- Total current assets 161,486 88,085 -------- -------- ----- ----- Oil and gas properties - using the full- cost method of accounting 3,124,67 3,130,32 9 7 Less accumulated depreciation, depletion and 2,816,00 2,791,00 amortization 0 0 -------- -------- ----- ----- Net oil and gas 308,679 339,327 properties -------- -------- ----- ----- $ 470,165 427,412 ======= ======= Liabilities and Partners' Equity - ---------------------------- - ------------
Current liability - $ 718 736 distributions payable -------- -------- ----- ----- Partners' equity: General partners (58,304) (65,081) Limited partners 527,751 491,757 -------- -------- ----- ----- Total partners' equity 469,447 426,676 -------- -------- ----- ----- $ 470,165 427,412 ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 2002, 2001 and 2000
2002 2001 2000 ------ ------ ------ Revenues - -------------
Oil and gas $ 822,546 1,009,78 1,208,57 4 5 Interest 647 4,572 8,672 Miscellaneous 9,163 - 126 -------- -------- -------- ---- ---- ---- 832,356 1,014,35 1,217,37 6 3 -------- -------- -------- ---- ---- ---- Expenses - ------------
Production 466,318 479,983 460,722 General and administrative 79,744 79,764 77,897 Depreciation, depletion and 25,000 53,000 20,000 amortization -------- -------- -------- ---- ---- ---- 571,062 612,747 558,619 -------- -------- -------- ---- ---- ---- Net income $ 261,294 401,609 658,754 ======= ======= =======
Net income allocated to:
Managing General Partner $ 25,766 40,915 61,088 ======= ======= ======= General Partner $ 2,863 4,546 6,788 ======= ======= ======= Limited partners $ 232,665 356,148 590,878 ======= ======= ======= Per limited partner unit $ 22.26 34.07 56.53 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 2002, 2001 and 2000
General Limited Partners Partners Total -------- -------- ----- Balance at December 31, 1999 $ (62,509) 690,785 628,276
Net income 67,876 590,878 658,754
Distributions (51,292) (564,502 (615,794 ) ) -------- -------- -------- -- -- -- Balance at December 31, 2000 (45,925) 717,161 671,236
Net income 45,461 356,148 401,609
Distributions (64,617) (581,552 (646,169 ) ) -------- -------- -------- -- -- -- Balance at December 31, 2001 (65,081) 491,757 426,676
Net income 28,629 232,665 261,294
Distributions (21,852) (196,671 (218,523 ) ) -------- -------- -------- -- -- -- Balance at December 31, 2002 $ (58,304) 527,751 469,447 ====== ====== ======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2002, 2001 and 2000
2002 2001 2000 ------ ------ ------ Cash flows from operating activities:
Cash received from oil and $ 800,557 1,112,80 1,147,50 gas sales 7 6 Cash paid to Managing General Partner for production expense, administrative fees and general and (566,121 (594,099 (496,877 administrative overhead ) ) ) Interest received 647 4,572 8,672 Miscellaneous settlement 9,163 - - -------- -------- -------- ----- ----- ----- Net cash provided by 244,246 523,280 659,301 operating activities -------- -------- -------- ----- ----- ----- Cash flows from investing activities:
Additions to oil and gas (535) (6,404) (31,032) properties Sale of oil and gas 6,183 780 - properties -------- -------- -------- ----- ----- ----- Net cash (used in) provided by investing activities 5,648 (5,624) (31,032) -------- -------- -------- ----- ----- ----- Cash flows used in financing activities:
Distributions to partners (218,541 (645,432 (615,920 ) ) ) -------- -------- -------- ----- ----- ----- Net increase (decrease) in cash and cash equivalents 31,353 (127,776 12,349 )
Beginning of year 38,153 165,929 153,580 -------- -------- -------- ----- ----- ----- End of year $ 69,506 38,153 165,929 ======= ======= ======= Reconciliation of net income to net cash provided by operating activities:
Net income $ 261,294 401,609 658,754
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and 25,000 53,000 20,000 amortization (Increase) decrease in (21,989) 103,023 (61,195) receivables (Decrease) increase in (20,059) (34,352) 41,742 payables -------- -------- -------- ----- ----- ----- Net cash provided by $ 244,246 523,280 659,301 operating activities ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Oil & Gas Income Fund IX-A, L.P. was organized under the laws of the state of Delaware on March 9, 1989, 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. 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 100% - contributions Oil and gas sales 90% 10% All other revenues 90% 10% Organization and offering 100% - costs (1) Amortization of organization 100% - costs Property acquisition costs 100% - Gain/loss on property 90% 10% disposition Operating and administrative 90% 10% costs (2) 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.
Prior to October 1, 2002, the Partnership calculated depletion of oil and gas properties under the units of revenue method. The Partnership changed methods of estimating depletion effective October 1, 2002 to the units of production method. The units of production method is more predominantly used throughout the oil and gas industry and will allow the Partnership to more closely align itself with its peers. The effect of this change in estimate was to increase 2002 depletion expense by $1,000 and decrease 2002 net income by $1,000.
Southwest Oil & Gas Income Fund IX-A, 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. In applying the units of revenue method for the years ended December 31, 2001, 2000 and for the nine months ended September 30, 2002, we have not excluded royalty and net profit interest payments from gross revenues as all of our royalty and net profit interests have been purchased and capitalized to the depletion basis of our proved oil and gas properties. As of December 31, 2002, 2001 and 2000 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
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.
Revenue Recognition We recognize 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, 2002, 2001 and 2000 the Partnership was overproduced by 403 mcf of gas.
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, 2002 and 2001 is $81,265 less than and $35,868 more, respectively, than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles.
Southwest Oil & Gas Income Fund IX-A, 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, 2002, 2001 and 2000 and there were 10,453 limited partner units outstanding held by 562, 562 and 561 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 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.
Southwest Oil & Gas Income Fund IX-A, 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 approximately $124.0 million of principal due between December 31, 2002 and December 31, 2004. The Managing General Partner is constantly monitoring its cash position and its ability to meet its financial obligations as they become due, and in this effort, is continually exploring various strategies for addressing its current and future liquidity needs. The Managing General Partner regularly pursues and evaluates recapitalization strategies and acquisition opportunities (including opportunities to engage in mergers, consolidations or other business combinations) and at any given time may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from operations, the Managing General Partner has adequate cash flow to fund debt service, developmental projects and day to day operations, but it is not sufficient to build a cash balance which would allow the Managing General Partner to meet its debt principal maturities scheduled for 2004. Therefore the Managing General Partner must renegotiate the terms of its various obligations or seek new lenders or equity investors in order to meet its financial obligations, specifically those maturing in 2004. The Managing General Partner would also 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 debt holders will agree to a course of action consistent with the Managing General Partner's requirements in restructurings the obligations. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the 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.
Southwest, as Managing General Partner, evaluated several liquidity alternatives for the partnerships in 2001 and 2002. During 2002, Southwest specifically pursued the possible roll-up and merger of twenty-one (21) partnerships with the general partner. Because of the complexities and conflicts of interest in such a transaction, the Managing General Partner did not make a formal repurchase offer in 2002 but has responded to limited partners desiring to sell their units in the partnerships on an "as requested" basis. Southwest anticipates that it will maintain this policy in 2003 because the aforementioned transaction is ongoing.
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, 2002, the Partnership has not been fined, cited or notified of any environmental violations and management was 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 Partnership's properties.
Southwest Oil & Gas Income Fund IX-A, 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 $79,200, $80,400 and $76,200 for the years ended December 31, 2002, 2001 and 2000, respectively. The amounts for administrative overhead attributable to operating the partnership properties have 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 that the Partnership also participates.
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 $34,500, $15,700 and $23,300 for the years ended December 31, 2002, 2001 and 2000, respectively. The amounts for oilfield services performed for the partnership by affiliates of the Managing General Partner have been deducted from gross oil and gas revenues in the determination of net profit interest.
Southwest Royalties, Inc., the Managing General Partner, was paid $73,200 during 2002, 2001 and 2000 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.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $92,000 and $49,900 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2002 and 2001, respectively.
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. Three purchasers accounted for 79% of the Partnership's total oil and gas production during 2002: Phillips 66 Company for 49%, Duke Energy Field Services LP for 16% and Plains Marketing LP for 14%. Three purchasers accounted for 71% of the Partnership's total oil and gas production during 2001: Phillips 66 Company for 45%, Duke Energy Field Services for 14% and Plains Marketing LP for 12%. Two purchasers accounted for 77% of the Partnership's total oil and gas production during 2000: Phillips 66 Company for 64%, and Plains Marketing LP for 13%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event any 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.
Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as follows:
Oil Gas (bbls) (mcf) -------- -------- ----- ---- Proved developed and undeveloped reserves -
January 1, 2000 321,000 1,225,00
Revisions of previous 27,000 518,000 estimates Production (25,000) (139,000 ) -------- -------- --- ----- December 31, 2000 323,000 1,604,00
Revisions of previous (89,000) (643,000 estimates ) Production (25,000) (122,000 ) -------- -------- --- ---- December 31, 2001 209,000 839,000
Revisions of previous 28,000 190,000 estimates Production (22,000) (111,000 ) -------- -------- --- --- December 31, 2002 215,000 918,000 ====== ====== Proved developed reserves -
December 31, 2000 305,000 1,517,00 ======= ======== = December 31, 2001 194,000 728,000 ======= ======== = December 31, 2002 202,000 797,000 ======= ======== =
All of the Partnership's reserves are located within the continental United States.
*Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2003. 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, 2003 are an average price of $29.28 per barrel. Southwest Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
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, 2003 are an average price of $4.30 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 developed non-producing 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, or receives cash.
Southwest Oil & Gas Income Fund IX-A, 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, 2002, 2001 and 2000 is presented below:
2002 2001 2000 ------ ------ ------
Future cash inflows $ 10,248,0 5,740,00 23,342,0 00 0 00 Production and development 4,482,00 2,872,00 8,358,00 costs 0 0 0 -------- -------- -------- ----- ------ ------ Future net cash flows 5,766,00 2,868,00 14,984,0 0 0 00 10% annual discount for estimated timing of cash flows 2,406,00 1,159,00 7,071,00 0 0 0 -------- -------- -------- ----- ----- ------ Standardized measure of discounted future net cash flows $ 3,360,00 1,709,00 7,913,00 0 0 0 ======= ======= ========
The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2002, 2001 and 2000 are as follows:
2002 2001 2000 ------ ------ ------
Sales of oil and gas produced, net of production costs $ (356,000 (530,000 (748,000 ) ) ) Changes in prices and 1,375,00 (5,896,0 4,096,00 production costs 0 00) 0 Changes of production rates (timing) and others (84,000) 392,000 (142,000 ) Sales of minerals in place - - Revisions of previous quantities estimates 545,000 (961,000 1,519,00 ) 0 Accretion of discount 171,000 791,000 290,000 Discounted future net cash flows - Beginning of year 1,709,00 7,913,00 2,898,00 0 0 0 -------- -------- -------- ---- ---- ---- End of year $ 3,360,00 1,709,00 7,913,00 0 0 0 ======= ======= =======
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 Oil & Gas Income Fund IX-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
8. Selected Quarterly Financial Results - (unaudited)
Quarter -------------------------------------- -------- First Second Third Fourth ------ ------- ------ ------ 2002: Total revenues $ 161,960 220,435 238,608 211,353 Total expenses 124,690 148,517 162,396 135,459 Net income 37,270 71,918 76,212 75,894 Net income per limited partners unit 3.16 6.20 6.50 6.40
2001: Total revenues $ 323,891 287,175 229,021 174,269 Total expenses 122,607 165,840 169,906 154,394 Net income 201,284 121,335 59,115 19,875 Net income per limited partners unit 17.24 10.29 4.92 1.62
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.
Name Age Position - ----------------------- --- ----------------------------- - ---------------------- -- ----------------------------- H. H. Wommack, III 47 Chairman of the Board, President, Director and Chief Executive Officer James N. Chapman(1) 40 Director William P. Nicoletti(2) 57 Director Joseph J. Radecki, Jr. 44 Director (2) Richard D. Rinehart(1) 67 Director John M. White(2) 46 Director Herbert C. Williamson, 54 Director III(1) Bill E. Coggin 48 Executive Vice President and Chief Financial Officer J. Steven Person 44 Vice President, Marketing
(1) Member of the Compensation Committee
(2) Member of the Audit Committee
H. H. Wommack, III has served as Chairman of the Board, President, Chief Executive Officer and a director since Southwest's founding in 1983. Since 1997 Mr. Wommack has served as President, Chief Executive Officer and Chairman of SRH, Southwest's former parent and current holder of 10% of its voting share capital. Since 1997 Mr. Wommack has served as chairman of the board of directors of Midland Red Oak Realty, Inc. From 1997 until December 2000, Mr. Wommack served as chairman of the board of directors of Basic Energy Services, Inc. and since December 2000 has continued to serve on Basic's board of directors. Prior to Southwest's formation, Mr. Wommack was a self-employed independent oil and gas producer engaged in the purchase and sale of royalty and working interests in oil and gas leases and the drilling of wells. Mr. Wommack graduated from the University of North Carolina at Chapel Hill and received his law degree from the University of Texas.
James N. Chapman has served as a director since April 19, 2002. Mr. Chapman has been involved in the investment banking industry for 18 years, presently acting as a capital markets and strategic planning consultant with private and public companies across a range of industries, including metals, mining, manufacturing, aerospace, airline, service and healthcare. Prior to establishing an independent consulting practice, Mr. Chapman worked for The Renco Group, Inc., a multi-billion private corporation in New York, for which Mr. Chapman developed and implemented financing and merger and acquisitions strategies for Renco's diverse portfolio of companies. Prior to Renco, Mr. Chapman was a founding principal of Fieldstone Private Capital Group, a capital markets advisory firm that he joined upon its inception in August 1990. Prior to joining Fieldstone, Mr. Chapman worked for Bankers Trust Company for six years, most recently in the BT Securities Capital Markets area. Mr. Chapman received an MBA degree with distinction from the Amos Tuck School at Dartmouth College and was elected an Edward Tuck Scholar. He received his BA degree with distinction magna cum laude, at Dartmouth College, was elected to Phi Beta Kappa and was a Rufus Choate Scholar.
William P. Nicoletti has served as a director since April 19, 2002. Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., an investment banking and financial advisory firm. He was formerly a senior officer and head of the Energy Investment Banking Groups of E. F. Hutton & Company Inc., Paine Webber, Incorporated and McDonald Investments Inc. Mr. Nicoletti is Chairman of the board of directors of Russell-Stanley Holdings, Inc., a manufacturer and marketer of steel and plastic industrial containers. He is a director of Mark WestEnergy Partners, L.P., a business engaged in the gathering and processing of natural gas and the fractionation and storage of natural gas liquids. Mr. Nicoletti is also a Director and Chairman of the Audit Committee of Star Gas Partners, L.P., the nation's largest retail distributor of home heating oil and a major retail distributor of propane gas. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA degree from Columbia University Graduate School of Business.
Joseph J. Radecki, Jr. has served as a director since April 19, 2002. Mr. Radecki is currently a Managing Director in the Leveraged Finance Group of CIBC World Markets where he is principally responsible for the firm's financial restructuring and distressed situation advisory practice. Prior to joining CIBC World Markets, Mr. Radecki was an Executive Vice President and Director of the Financial Restructuring Group of Jefferies & Company, Inc. from 1990 to 1998. From 1983 until 1990, Mr. Radecki was First Vice President in the International Capital Markets Group at Drexel Burnham Lambert, Inc., where he specialized in financial restructurings and recapitalizations. Over the past fourteen years, Mr. Radecki has been integrally involved in over 120 transactions totaling nearly $50 billion in recapitalized securities. Mr. Radeki currently serves as a Director of Wherehouse Entertainment, Inc., a music and video specialty retailer, and RBX Corporation, a manufacturer of rubber and plastic foam and other polymer products. He has previously served as Chairman of the Board of American Rice, Inc., an international rice miller and marketer, as a member of the Board of Directors of Service America Corporation, a national food service management firm, Bucyrus International, Inc., a mining equipment manufacturer, and ECO-Net, a non-profit engineering related network firm. Mr. Radecki graduated magna cum laude in 1980 from Georgetown University with a B.A. in Government.
Richard D. Rinehart has served as a director since April 19, 2002. Mr. Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel Resources, Inc. PetroCap, Inc. provides investment and merchant banking services to a variety of clients active in the oil and gas industry. Kestrel Resources, Inc. is a privately owned oil and gas operating company. He served as Director of Coopers & Lybrand's Energy Systems and Services Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to joining Coopers & Lybrand, he was chief executive officer/founder of Dawn Information Resources, Inc., formed in 1986 and acquired by Coopers & Lybrand in early 1991. Mr. Rinehart served as CEO of Terrapet Energy Corporation during the period 1982 through 1986. Prior to the formation of Terrapet in 1982, he was employed as President of the Terrapet Division of E.I. DuPont de Nemours and Company. Before its acquisition by DuPont, he served as CEO and President of Terrapet Corp., a privately owned E & P company. Before the formation of Terrapet Corp. in 1972, he was manager of supplementary recovery methods and senior evaluation engineer with H. J. Gruy and Associates, Inc., Dallas, Texas.
John M. White has served as a director since April 19, 2002 Mr. White is currently an oil and gas analyst with BMO Nesbitt Burns, responsible for Fixed Income research on oil, gas and energy companies. Prior to joining BMO Nesbitt Burns in 1998, Mr. White was responsible for Fixed Income research on the oil and gas industry at John S. Herold, Inc., an independent oil and gas research and consulting firm. Mr. White's experience also includes managing a portfolio of oil and gas loans for The Bank of Nova Scotia, which included independent exploration and production companies, oil service companies, gas pipelines, gas processors and refiners. Prior to entering banking, Mr. White was with BP Exploration, where he worked primarily in exploration and production.
Herbert C. Williamson, III has served as a director since April 19, 2002. At present, Mr. Williamson is self-employed as a consultant. From March 2001 to March 2002 Mr. Williamson served as an investment banker with Petrie Parkman & Co. From April 1999 to March 2001 Mr. Williamson served as chief financial officer and from August 1999 to March 2001 as a director of Merlon Petroleum Company, a private oil and gas company involved in exploration and production in Egypt. Mr. Williamson served as executive vice president, chief financial officer and director of Seven Seas Petroleum, Inc., a publicly traded oil and gas exploration company, from March 1998 to April 1999. From 1995 through April 1998, he served as director in the Investment Banking Department of Credit Suisse First Boston. Mr. Williamson served as vice chairman and executive vice president of Parker and Parsley Petroleum Company, a publicly traded oil and gas exploration company (now Pioneer Natural Resources Company) from 1985 through 1995.
Bill E. Coggin has served as Vice President and Chief Financial Officer since joining the Managing General Partner in 1985. Previously, Mr. Coggin was Controller for Rod Ric Corporation, an oil and gas drilling company, and for C.F. Lawrence & Associates, a large independent oil and gas operator. Mr. Coggin received a B.S. in Education and a B.A. in Accounting from Angelo State University.
J. Steven Person has served as Vice President, Marketing since joining the Managing General Partner in 1989. Mr. Person began in the investment industry with Dean Witter in 1983. Prior to joining the Managing General Partner, Mr. Person was a senior wholesaler with Capital Realty, Inc. While at Capital Realty, he was involved in the syndication of mortgage based securities through the major brokerage houses. Mr. Person received a B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist University.
Key Employees
Jon P. Tate, age 45, has served as Vice President, Land and Assistant Secretary of the Managing General Partner since 1989. From 1981 to 1989, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as land manager. Mr. Tate is a member of the Permian Basin Landman's Association.
R. Douglas Keathley, age 47, has served as Vice President, Operations of the Managing General Partner since 1992. Before joining us, Mr. Keathley worked as a senior drilling engineer for ARCO Oil and Gas Company and in similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.
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 $73,200 during 2002, 2001 and 2000 as an annual 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 repurchase offers to the limited partners, the Managing General Partner also owns 452.5 limited partner units, a 3.9% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 12.9%.
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 in the Partnership 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. 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. To our knowledge, except under applicable community property laws or as otherwise indicated, the persons named in the table have sole voting and sole investment control with regard to all limited partner units beneficially owned. We are presenting ownership information as of March 1, 2003. A list of beneficial owners of limited partner units, acquired by the Managing General Partner, is as follows:
Amount and Nature of Percen t Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------- ---------- ------ -------------- -------------- ------ ----- Limited Partnership Southwest Royalties, Directly 3.9% Interest Inc. Owns Managing General 452.5 Partner Units 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly 3.9% Interest Owns Chairman of the 452.5 Board, Units President, and CEO of Southwest 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 2002, the Managing General Partner received $73,200 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 working interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $79,200 for administrative overhead attributable to operating such properties during 2002.
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 $34,500 for the year ended December 31, 2002.
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 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 of Limited Partnership of Southwest Oil & Gas Income Fund IX- A, L.P., dated March 9, 1989. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1989.)
(b) Agreement of Limited Partnership of Southwest Oil & Gas Income Fund IX- A, L.P. dated October 25, 1989. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(c) Certificate of Amendment of Limited Partnership of Southwest Oil & Gas Income Fund IX-A, L.P., dated July 21, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
99.1 Certification pursuant to 18 U.S.C. Section 1350 99.2 Certification pursuant to 18 U.S.C. Section 1350
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the quarter ended December 31, 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 Oil & Gas Income Fund IX-A, 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 28, 2003
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 By: /s/ James N. Chapman - --------------------------- ------------------------ - -------------------- ----------------------- H. H. Wommack, III, James N. Chapman, Chairman of the Board, Director President, Director and Chief Executive Officer
Date: March 28, 2003 Date: March 28, 2003
By: /s/ William P. By: /s/ Joseph J. Nicoletti Radecki, Jr. - --------------------------- ------------------------ - -------------------- ----------------------- William P. Nicoletti, Joseph J. Radecki, Jr., Director Director
Date: March 28, 2003 Date: March 28, 2003
By: /s/ Richard D. By: /s/ John M. White Rinehart - --------------------------- ------------------------ - -------------------- ----------------------- Richard D. Rinehart, John M. White, Director Director
Date: March 28, 2003 Date: March 28, 2003
By: /s/ Herbert C. Williamson, III - --------------------------- - -------------------- Herbert C. Williamson, III, Director
Date: March 28, 2003
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil & Gas Income Fund IX-A, L.P.;
2. Based on my knowledge, this annual 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 annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d- 14) for the registrant and we have: a) designed such disclosure controls and procedures 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 annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 28, 2003
/s/ H.H. Wommack, III H. H. Wommack, III Chairman, President, Director and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund IX-A, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil & Gas Income Fund IX-A, L.P.;
2. Based on my knowledge, this annual 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 annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d- 14) for the registrant and we have: a) designed such disclosure controls and procedures 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 annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 28, 2003
/s/ Bill E. Coggin Bill E. Coggin Executive Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund IX-A, L.P.
Exhibit Index
Item No. Description Page No.
Exhibit 99.1 Certification pursuant to 18 U.S.C. 42 Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99.2 Certification pursuant to 18 U.S.C. 43 Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
CERTIFICATION PURSUANT TO 19 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Oil & Gas Income Fund IX-A, Limited Partnership (the "Company") on Form 10- K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, H.H. Wommack, III, Chief Executive Officer of the Managing General Partner of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, 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.
Date: March ___, 2003
/s/ H.H. Wommack, III H. H. Wommack, III Chairman, President, Director and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund IX-A, L.P.
CERTIFICATION PURSUANT TO 19 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Oil & Gas Income Fund IX-A, Limited Partnership (the "Company") on Form 10- K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Bill E. Coggin, Chief Financial Officer of the Managing General Partner of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:
(3) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(4) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.
Date: March ___, 2003
/s/ Bill E. Coggin Bill E. Coggin Executive Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund IX-A, L.P.