Item 1. Business
General Southwest Royalties Institutional Income Fund IX-B, 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 the minimum capital requirements on September 26, 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 royalty or overriding royalty interests and working interests in oil and gas properties that were converted into net profits interests or other nonoperating interests. The Partnership purchased either all or part of the rights and obligations under various oil and gas leases.
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 245 individuals, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of oil and gas properties and the marketing of production from such properties. H. H. Wommack, III, a stockholder, director, President and Treasurer of the Managing General Partner, is also a general partner. The Partnership has no employees.
Principal Products, Marketing and Distribution The Partnership has acquired and holds royalty, overriding royalty and net profits 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.
The recent strength in the price of crude oil reflects a continued growth in demand for energy. The worldwide demand for oil continues to grow. The United States dependence on foreign oil reached a record 51% in 1996. The supply of oil is not keeping up with the demand on either a domestic or worldwide economic basis. Oil production in the United States fell for the fifth straight year, dropping 1.8% to 6.45 million barrels per day in 1996. At the same time, economic recovery in the world economy continues to apply upward pressure on demand. Current oil consumption of over 70 million barrels per day is growing on an annual basis. This is especially acute in the lesser developed countries as they move toward industrialization. Supply and demand for oil has moved very close to being in balance. The lack of excess capacity in the oil markets has helped push oil prices into the mid- 20's during 1996.
For the last several years, the natural gas industry in the United States has been affected generally by a surplus in available natural gas and enhanced delivery capability causing a general deterioration in natural gas prices. In 1996, natural gas prices recovered significantly after having been adversely affected for many years by the chronic oversupply. A colder than normal 1995 and 1996 winter for most of the nation and a cold start for the 1996 and 1997 heating season has increased demand, while supplies have declined creating a guarded optimism within the industry in regards to the 1997 gas price. January 1997's gas price is the highest the industry has seen since deregulation in 1985.
Following is a table of the ratios of revenues received from oil and gas production for the last three years:
Oil Gas
1996 65% 35% 1995 76% 24% 1994 67% 33%
As the table indicates, the majority of the Partnership's revenue is from its oil production; therefore, Partnership revenues will be highly dependent upon the future prices and demands for oil.
Seasonality of Business Although the demand for natural gas is highly seasonal, with higher demand in the colder winter months and in very hot summer months, the Partnership has been able to sell all of its natural gas, either through contracts in place or on the spot market at the then prevailing spot market price. As a result, the volumes sold by the Partnership have not fluctuated materially with the change of season.
Customer Dependence No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have material adverse impact on the Partnership. One purchaser accounted for 65% of the Partnership's total oil and gas production during 1996: Phillips 66 Company 65%. Two purchasers accounted for 68% of the Partnership's total oil and gas production during 1995: Phillips 66 Company and Fina Oil & Chemical Company, Inc. purchased 50% and 18%, respectively. Two purchasers accounted for 55% of the Partnership's total oil and gas production during 1994: Phillips 66 Company and Fina Oil & Chemical Company, Inc. purchased 38% and 17%, respectively.
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 net profits or royalty interests in producing oil and gas properties, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties.
Factors that may adversely affect the Partnership include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.
Regulation
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, 1996, there were 245 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, 1996, the Partnership possessed an interest in oil and gas properties located in Eddy and Lea Counties of New Mexico; Andrews, Borden, Cochran, Crane, Ector, Gaines, Garza, Howard, Pecos, Reagan, Schleicher, Stonewall, Terry, Ward, Winkler and Yoakum Counties of Texas. These properties consist of various interests in approximately 330 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 has not been any significant changes in properties during 1996, 1995 and 1994.
Upon a determination by Management that they were either not profitable to own or Management received an offer that exceeded the leases reserves, the following leases were sold.
During 1996, two leases were sold for approximately $259,700. The Rowena Lane and JP Davis were sold effective February 1996. The Partnership retained an overriding royalty interest in the JP Davis.
During 1995, five leases were sold for approximately $56,400. The Munn A #1 was sold effective May 1995, the Barber #1 and Zapalac #1 were sold effective August 1995; and the Percy Jones and Grayburg were sold effective November 1995.
During 1994, three leases were sold for approximately $57,000. The Harris C was sold effective February 1994, the Robertson G was sold effective March 1994 and the TSRH-D 48 #1 was sold effective May 1994.
Significant Properties The following table reflects the significant properties in which the Partnership has an interest:
Date Purchased No. of Proved Reserves* Name and Location and Interest Wells Oil (bbls) Gas (mcf)
Phillips/Odessa 1/90 at 6% 48 302,320 1,382,736 Properties, to 48% net 16 counties in profits Texas, 3 counties interests in New Mexico
Long Acquisition 8/90 at 47% 2 14,162 517,852 Lea County, net profits New Mexico interests
*The reserve estimates were prepared as of January 1, 1997, by Donald R. Creamer, P.E., an independent registered petroleum engineer. 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 operation conditions, price and costs, as of the date the estimation is made. Prices may include consideration of changes in existing price provided only by contractual arrangements, but not on escalations based upon future conditions.
An oil price of $23.86 per barrel was used in the preparation of the reserve report as of January 1, 1997. The West Texas Intermediate posted price at December 31, 1996 of $24.25 was used as the beginning basis for the oil price. Oil price adjustments from $24.25 per barrel were made in the individual evaluations to allow for the average difference between recent prices actually received (current prices) and the West Texas Intermediate posted price on the sales date. This effectively adjusts for temperature, gravity, transportation and impurities on an individual property basis to arrive at a fair value for the selling price.
A gas price of $3.32 per mcf was used in the preparation of the reserve report as of January 1, 1997. The El Paso Permian Basin Index posted price at December 31, 1996 of $3.59 was used as the beginning basis for the gas price. Gas price adjustments from $3.59 per mcf were made in the individual evaluations to allow for the average difference between recent prices actually received (current prices) and the El Paso Permian Basin Index posted price on the sales date. This effectively adjusts for temperature, gravity, transportation and impurities on an individual property basis to arrive at a fair value for the selling price.
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 1996.
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 1996 through the solicitation of proxies or otherwise.
Part II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
Market Information Limited partnership interests, or units, in the Partnership were initially offered and sold for a price of $500. Limited partner units are not traded on any exchange and there is no public or organized trading market for them. The Managing General Partner has become aware of certain limited and sporadic transfers of units between limited partners and third parties, but has no verifiable information regarding the prices at which such units have been transferred. Further, a transferee may not become a substitute limited partner without the consent of the Managing General Partner.
The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion. In 1996, 40 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $80.66 per unit. In 1995 and 1994, no limited partner units were tendered to and purchased by the Managing General Partner.
Number of Limited Partner Interest Holders As of December 31, 1996, there were 622 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 monthly 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 1996, twelve monthly distributions were made totaling $549,668, with $496,568 distributed to the limited partners and $53,100 to the general partners. For the year ended December 31, 1996, distributions of $50.76 per limited partner unit were made, based upon 9,782 limited partner units outstanding. For the year ended December 31, 1995, twelve monthly distributions were made totaling $246,193 with $223,073 distributed to the limited partners and $23,120 to the general partners. For the year ended December 31, 1995, distributions of $22.80 per limited partner unit were made, based upon 9,782 limited partner units outstanding. For the year ended December 31, 1994, twelve monthly distributions were made totaling $353,555 with $319,645 distributed to the limited partners and $33,910 to the general partners. For the year ended December 31, 1994, distributions of $32.68 per limited partner unit were made, based upon 9,782 limited partner units outstanding.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 1996, 1995, 1994, 1993 and 1992 should be read in conjunction with the financial statements included in Item 8:
Years ended December 31, ----------------------------------------------------- 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- Revenues $ 418,342 280,264 363,460 547,416 483,317
Net income (loss) 266,067 44,550 54,149 75,679 (45,840)
Partners' share of net income (loss):
General partners 34,107 20,055 28,025 46,328 39,776
Limited partners 231,960 24,495 26,124 29,351 (85,616)
Limited partners' net income (loss) per unit 23.71 2.50 2.67 3.00 (8.75)
Limited partners' cash distributions per unit 50.76 22.80 32.68 83.33 51.89
Total assets $ 1,092,739 1,376,416 1,578,681 1,877,764 2,686,164
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General The Partnership was formed to acquire nonoperating interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. Net revenues from producing oil and gas properties are not reinvested in other revenue producing assets except to the extent that producing facilities and wells are reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves. The economic life of the Partnership thus depends on the period over which the Partnership's oil and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, lease operating expenses, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements and on the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately. Net income available for distribution to the limited partners is therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing workovers during the next two years to enhance production. The Partnership may undergo an increase later in 1997 and possibly in 1998. Thereafter, the Partnership could possibly experience a normal decline of 8% to 10% per year.
Results of Operations
A. General Comparison of the Years Ended December 31, 1996 and 1995
The following table provides certain information regarding performance factors for the years ended December 31, 1996 and 1995:
Year Ended Percentage December 31, Increase 1996 1995 (Decrease) ---- ---- ---------- Average price per barrel of oil $ 21.43 15.39 39% Average price per mcf of gas $ 2.07 1.17 77% Oil production in barrels 29,000 41,900 (31%) Gas production in mcf 163,800 177,800 (8%) Income from net profits interests $ 414,279 278,954 49% Partnership distributions $ 549,668 246,193 123% Limited partner distributions $ 496,568 223,073 123% Per unit distribution to limited partners $ 50.76 22.80 123% Number of limited partner units 9,782 9,782
Revenues
The Partnership's income from net profits interests increased to $414,279 from $278,954 for the years ended December 31, 1996 and 1995, respectively, an increase of 49%. The principal factors affecting the comparison of the years ended December 31, 1996 and 1995 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 1996 as compared to the year ended December 31, 1995 by 39%, or $6.04 per barrel, resulting in an increase of approximately $253,100 in income from net profits interests. Oil sales represented 65% of total oil and gas sales during the year ended December 31, 1996 as compared to 76% during the year ended December 31, 1995.
The average price for an mcf of gas received by the Partnership increased during the same period by 77%, or $.90 per mcf, resulting in an increase of approximately $160,000 in income from net profits interests.
The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $413,100. 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 12,900 barrels or 31% during the year ended December 31, 1996 as compared to the year ended December 31, 1995, resulting in a decrease of approximately $276,400 in income from net profits interests.
Gas production decreased approximately 14,000 mcf or 8% during the same period, resulting in a decrease of approximately $29,000 in income from net profits interests.
The total decrease in income from net profits interests due to the change in production is approximately $305,400. The decrease is primarily a result of property sales, a well being shut-in during 1996 and scale damage to two wells.
3. Lease operating costs and production taxes were 5% lower, or approximately $28,300 less during the year ended December 31, 1996 as compared to the year ended December 31, 1995.
Costs and Expenses
Total costs and expenses decreased to $152,275 from $235,714 for the years ended December 31, 1996 and 1995, respectively, a decrease of 35%. The decrease is the result of lower general and administrative expense and depletion expense.
1. General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 3% or approximately $2,400 during the year ended December 31, 1996 as compared to the year ended December 31, 1995.
2. Depletion expense decreased to $75,000 for the year ended December 31, 1996 from $156,000 for the same period in 1995. This represents a decrease of 52%. 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.
A contributing factor to the decline in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine the Partnership's reserves for January 1, 1997 as compared to 1996. Another contributing factor was due to the impact of revisions of previous estimates on reserves. 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 decreased depletion expense approximately $38,000 as of December 31, 1995.
B. General Comparison of the Years Ended December 31, 1995 and 1994
The following table provides certain information regarding performance factors for the years ended December 31, 1995 and 1994:
Year Ended Percentage December 31, Increase 1995 1994 (Decrease) ---- ---- ---------- Average price per barrel of oil $ 15.39 14.19 8% Average price per mcf of gas $ 1.17 1.41 (17%) Oil production in barrels 41,900 48,500 (14%) Gas production in mcf 177,800 238,800 (26%) Income from net profits interests $ 278,954 361,736 (23%) Partnership distributions $ 246,193 353,555 (30%) Limited partner distributions $ 223,073 319,645 (30%) Per unit distribution to limited partners $ 22.80 32.68 (30%) Number of limited partner units 9,782 9,782
Revenues
The Partnership's income from net profits interests decreased to $278,954 from $361,736 for the years ended December 31, 1995 and 1994, respectively, a decrease of 23%. The principal factors affecting the comparison of the years ended December 31, 1995 and 1994 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 1995 as compared to the year ended December 31, 1994 by 8%, or $1.20 per barrel, resulting in an increase of approximately $58,200 in income from net profits interests. Oil sales represented 76% of total oil and gas sales during the year ended December 31, 1995 as compared to 67% during the year ended December 31, 1994.
The average price for an mcf of gas received by the Partnership decreased during the same period by 17%, or $.24 per mcf, resulting in a decrease of approximately $57,300 in income from net profits interests.
The net total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $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 6,600 barrels or 14% during the year ended December 31, 1995 as compared to the year ended December 31, 1994, resulting in a decrease of approximately $101,600 in income from net profits interests.
Gas production decreased approximately 61,000 mcf or 26% during the same period, resulting in a decrease of approximately $71,400 in income from net profits interests.
The total decrease in income from net profits interests due to the change in production is approximately $173,000. The decrease is a result of property sales and equipment, mechanical and downhole failures during 1995.
3. Lease operating costs and production taxes were 13% lower, or approximately $89,000 less during the year ended December 31, 1995 as compared to the year ended December 31, 1994. The decrease is a result of property sales and workover costs incurred in 1994.
Costs and Expenses
Total costs and expenses decreased to $235,714 from $309,311 for the years ended December 31, 1995 and 1994, respectively, a decrease of 24%. The decline is the result of a decrease in general and administrative expense and depletion expense.
1. General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 4% or approximately $3,500 during the year ended December 31, 1995 as compared to the year ended December 31, 1994.
2. Depletion expense decreased to $156,000 for the year ended December 31, 1995 from $197,000 for the same period in 1994. This represents a decrease of 21%. 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. Consequently, depletion will fluctuate in direct relation to oil and gas revenues. As noted above, oil and gas revenues declined due to a decline in gas prices and oil and gas production for the year ended December 31, 1995 as compared to the same period for 1994. Depletion reflected a comparable decline.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 1996, 1995 and 1994 was $266,067, $44,550 and $54,149, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 1996, 1995 and 1994 would have been $341,067, $200,550 and $280,250, respectively. Correspondingly, Partnership distributions for the years ended December 31, 1996, 1995 and 1994 were $549,668, $246,193 and $353,555. These differences are indicative of the changes in oil and gas prices, production and properties during 1996, 1995 and 1994.
The sources for the 1996 distributions of $549,668 were oil and gas operations of approximately $266,100 and property sales of approximately $259,900, with the balance from available cash on hand at the beginning of the period. The sources for the 1995 distributions of $246,193 were oil and gas operations of approximately $211,100 and property sales of approximately $56,200, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1994 distributions of $353,555 were oil and gas operations of approximately $298,600 and property sales of approximately $57,000, resulting in excess cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 1996 were $549,668 of which $496,568 was distributed to the limited partners and $53,100 to the general partners. The per unit distribution to limited partners during the same period was $50.76. Total distributions during the year ended 1995 were $246,193 of which $223,073 was distributed to the limited partners and $23,120 to the general partners. The per unit distribution to limited partners during the same period was $22.80. Total distributions during the year ended 1994 were $353,555 of which $319,645 was distributed to the limited partners and $33,910 to the general partners. The per unit distribution to limited partners during the same period was $32.68.
Since inception of the Partnership, cumulative monthly cash distributions of $4,875,206 have been made to the partners. As of December 31, 1996, $4,424,912 or $452.35 per limited partner unit, has been distributed to the limited partners, representing a 90% return of the 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 in 1996.
Cash flows provided by operating activities were approximately $266,100 in 1996 compared to approximately $211,100 in 1995 and approximately $298,600 in 1994. The primary sources of the 1996 cash flow from operating activities were profitable operations.
Cash flows provided by investing activities were approximately $259,900 in 1996 compared to approximately $56,200 in 1995 and approximately $57,000 in 1994. The principal source of the 1996 cash flow from investing activities was the sale of oil and gas properties.
Cash flows used in financing activities were approximately $549,700 in 1996 compared to approximately $246,200 in 1995 and approximately $353,200 in 1994. The only use in financing activities was the distributions to partners.
As of December 31, 1996, the Partnership had approximately $161,600 in working capital. The Managing General Partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of the Partnership.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Report of Independent Accountants. . . . . . . . . . . . . . . . . . . .20
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . .22
Statement of Changes in Partners' Equity . . . . . . . . . . . . . . . .23
Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . .24
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . .26
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners Southwest Royalties Institutional Income Fund IX-B, L.P. Midland, Texas
We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund IX-B, L.P. as of December 31, 1996 and 1995, and the related statements of operations, changes in partners' equity and cash flows for each of the three years in the period ended December 31, 1996. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund IX-B, L.P. as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
JOSEPH DECOSIMO AND COMPANY A Tennessee Registered Limited Liability Partnership
Chattanooga, Tennessee March 14, 1997
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership) Balance Sheets December 31, 1996 and 1995
1996 1995 ---- ----
Assets
Current assets: Cash and cash equivalents $ 13,489 37,215 Receivable from Managing General Partner 148,536 73,754 --------- --------- Total current assets 162,025 110,969 --------- --------- Oil and gas properties - using the full-cost method of accounting 3,286,714 3,546,447 Less accumulated depreciation, depletion and amortization 2,356,000 2,281,000 --------- --------- Net oil and gas properties 930,714 1,265,447 --------- --------- $ 1,092,739 1,376,416 ========= ========= Liabilities and Partners' Equity
Current liability - Distribution payable $ 378 454 --------- --------- Partners' equity: General partners (44,279) (25,286) Limited partners 1,136,640 1,401,248 --------- --------- Total partners' equity 1,092,361 1,375,962 --------- --------- $ 1,092,739 1,376,416 ========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 1996, 1995 and 1994
1996 1995 1994 ---- ---- ---- Revenues
Income from net profits interests $ 414,279 278,954 361,736 Interest 4,063 1,310 1,724 ------- ------- ------- 418,342 280,264 363,460 ------- ------- ------- Expenses
General and administrative 77,275 79,714 83,210 Depreciation, depletion and amortization 75,000 156,000 226,101 ------- ------- ------- 152,275 235,714 309,311 ------- ------- ------- Net income $ 266,067 44,550 54,149 ======= ======= =======
Net income allocated to:
Managing General Partner $ 30,696 18,049 25,222 ======= ======= ======= General Partner $ 3,411 2,006 2,803 ======= ======= ======= Limited partners $ 231,960 24,495 26,124 ======= ======= ======= Per limited partner unit $ 23.71 2.50 2.67 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 1996, 1995 and 1994
General Limited Partners Partners Total -------- -------- -----
Balance at December 31, 1993 $ (16,336) 1,893,347 1,877,011
Net income 28,025 26,124 54,149
Distributions (33,910) (319,645) (353,555) ------- --------- --------- Balance at December 31, 1994 (22,221) 1,599,826 1,577,605
Net income 20,055 24,495 44,550
Distributions (23,120) (223,073) (246,193) ------- --------- --------- Balance at December 31, 1995 (25,286) 1,401,248 1,375,962
Net income 34,107 231,960 266,067
Distributions (53,100) (496,568) (549,668) ------- --------- --------- Balance at December 31, 1996 $ (44,279) 1,136,640 1,092,361 ======= ========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 1996, 1995 and 1994
1996 1995 1994 ---- ---- ----
Cash flows from operating activities:
Cash received from net profits interests $ 339,344 290,135 380,099 Cash paid to suppliers (77,281) (80,363) (83,210) Interest received 4,063 1,310 1,724 -------- -------- -------- Net cash provided by operating activities 266,126 211,082 298,613 -------- -------- -------- Cash flows provided by investing activities:
Sale of oil and gas properties 259,892 56,215 56,985 -------- -------- -------- Cash flows used in financing activities:
Distributions to partners (549,744) (246,160) (353,232) -------- -------- -------- Net increase (decrease) in cash and cash equivalents (23,726) 21,137 2,366
Beginning of year 37,215 16,078 13,712 -------- -------- -------- End of year $ 13,489 37,215 16,078 ======== ======== ========
(continued)
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership) Statements of Cash Flows, continued Years ended December 31, 1996, 1995 and 1994
1996 1995 1994 ---- ---- ----
Reconciliation of net income to net cash provided by operating activities:
Net income $ 266,067 44,550 54,149
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 75,000 156,000 226,101 (Increase) decrease in receivables (74,935) 11,187 18,363 Decrease in payables (6) (655) - ------- ------- ------- Net cash provided by operating activities $ 266,126 211,082 298,613 ======= ======= =======
Supplemental schedule of noncash investing and financing activities:
Sale of oil and gas properties included in receivable from Managing General Partner $ - 159 -
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Summary of Significant Accounting Policies
Oil and Gas Properties Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.
Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership's independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.
Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 1996, 1995 and 1994, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership)
Notes to Financial Statements
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. Actual results could differ from those estimates.
Syndication Costs Syndication costs are accounted for as a reduction of partnership equity.
Environmental Costs The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Gas Balancing The Partnership utilizes the sales method of accounting for gas- balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 1996, 1995 and 1994 the Partnership was overproduced by 951, 5,990 and 9,244 mcf of gas, respectively.
Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership)
Notes to Financial Statements
Income Taxes - continued 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, 1996 and 1995 is $58,817 more and $182,132, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
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, 1996, 1995 and 1994, there were 9,782 limited partner units outstanding.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Organization Southwest Royalties Institutional Income Fund IX-B, 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 -------- --------
Oil and gas sales 90% 10% Interest income on capital contributions 100% - All other revenues 90% 10% Organization and offering costs (1) 100% - Syndication costs 100% - Amortization of organization costs 100% - Property acquisition costs 100% - Gain/loss on property disposition 90% 10% Operating and administrative costs (2) 90% 10% Depreciation, depletion and amortization of oil and gas properties 100% - All other costs 90% 10%
(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.
(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.
Southwest Royalties Institutional Income Fund IX-B, L.P. (a Delaware limited partnership)
Notes to Financial Statements
3. Oil and Gas Properties Costs incurred in connection with the Partnership's oil and gas producing activities for the years ended December 31, 1996, 1995 and 1994 are as follows:
1996 1995 1994 ---- ---- ----
Depreciation, depletion and amortization $ 75,000 156,000 197,000 ====== ======= =======
All of the Partnership's properties were proved when acquired.
4. Commitments and Contingent Liabilities 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, 1996, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership's properties.
Southwest Royalties Institutional Income Fund IX-B, 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 is usual in the industry and 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 $96,000, $113,000 and $124,000 for the years ended December 31, 1996, 1995 and 1994, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.
Certain subsidiaries of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $4,000, $4,000 and $5,000 for the years ended December 31, 1996, 1995 and 1994, respectively, and the Managing General Partner believes that these costs are comparable to similar charges paid by the Partnership to unrelated third parties.
Southwest Royalties, Inc., the Managing General Partner, was paid $68,400 during 1996, 1995 and 1994 as an administrative fee for indirect general and administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $148,536 and $73,754 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 1996 and 1995, respectively.
In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership approximating $100 for the year ended December 31, 1996. There were no legal services provided for the year ended December 31, 1995 and approximately $100 for the year ended December 31, 1994.
6. Major Customers and Significant Leases During 1996, one customers purchased 65% of the Partnership's oil and gas production. During 1995, two customers purchased 50% and 18% of the Partnership's oil and gas production. During 1994, two customers purchased 38% and 17% of the Partnership's oil and gas production.
There was no one lease that accounted for more than 15% of the Partnership's gross revenues.
Southwest Royalties Institutional Income Fund IX-B, 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 (bbls) Gas (mcf) ---------- --------- Proved developed and undeveloped reserves -
January 1, 1994 273,000 2,117,000
Revisions of previous estimates 100,000 133,000 Production (49,000) (239,000) Sale of minerals in place - (115,000) ------- --------- December 31, 1994 324,000 1,896,000
Revisions of previous estimates 57,000 (127,000) Production (42,000) (178,000) Sale of minerals in place (8,000) (40,000) ------- --------- December 31, 1995 331,000 1,551,000
Revisions of previous estimates 114,000 675,000 Production (29,000) (164,000) Sale of minerals in place (61,000) - ------- --------- December 31, 1996 355,000 2,062,000 ======= =========
Proved developed reserves -
December 31, 1994 284,000 1,660,000 ======= ========= December 31, 1995 299,000 1,524,000 ======= ========= December 31, 1996 337,500 2,032,000 ======= =========
All of the Partnership's reserves are located within the continental United States.
Southwest Royalties Institutional Income Fund IX-B, 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, 1996, 1995 and 1994 is presented below:
1996 1995 1994
Future cash inflows, net of production and development costs $ 8,750,000 3,748,000 3,785,000 10% annual discount for estimated timing of cash flows 3,785,000 1,404,000 1,427,000 --------- --------- --------- Standardized measure of discounted future net cash flows $ 4,965,000 2,344,000 2,358,000 ========= ========= =========
The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 1996, 1995 and 1994 are as follows:
1996 1995 1994
Sales of oil and gas produced, net of production costs $ (788,000) (568,000) (590,000) Changes in price 2,655,000 580,000 319,000 Revisions to estimated production costs 89,000 (441,000) 249,000 Sales of minerals in place (202,000) (25,000) (33,000) Revisions of previous quantities estimates 472,000 195,000 154,000 Accretion of discount 395,000 245,000 186,000 Discounted future net cash flows - Beginning of year 2,344,000 2,358,000 2,073,000 --------- --------- --------- End of year $ 4,965,000 2,344,000 2,358,000 ========= ========= =========
Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Part III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as Managing General Partner. The names, ages, offices, positions and length of service of the directors and executive officers of Southwest Royalties, Inc. are set forth below. Each director and executive officer serves for a term of one year. The present directors of the Managing General Partner have served in their capacity since the Company's formation in 1983.
Name Age Position - -------------------- --- ------------------------------------- H. H. Wommack, III 41 Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
H. Allen Corey 41 Secretary and Director
Bill E. Coggin 42 Vice President and Chief Financial Officer
Richard E. Masterson 43 Vice President, Exploration and Acquisitions
Jon P. Tate 39 Vice President, Land and Assistant Secretary
Joel D. Talley 35 Vice President, Acquisitions and Exploitation Manager
R. Douglas Keathley 41 Vice President, Operations
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive Officer, Treasurer, principal stockholder and a director of the Managing General Partner, and has served as its President since the Company's organization in August, 1983. Prior to the formation of the Company, Mr. Wommack was a self-employed independent oil producer engaged in the purchase and sale of royalty and working interests in oil and gas leases, and the drilling of exploratory and developmental oil and gas wells. Mr. Wommack holds a J.D. degree from the University of Texas from which he graduated in 1980, and a B.A. from the University of North Carolina in 1977.
H. Allen Corey, a founder of the Managing General Partner, has served as the Managing General Partner's secretary and a director since its inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew pub restaurant chain based in the Southeast. Prior to his involvement with Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in Chattanooga, Tennessee. He is currently of counsel to the law firm of Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga, Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University Law School and B.A. degree from the University of North Carolina at Chapel Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with the Managing General Partner since 1985. Mr. Coggin was Controller for Rod Ric Corporation of Midland, Texas, an oil and gas drilling company, during the latter part of 1984. He was Controller for C.F. Lawrence & Associates, Inc., an independent oil and gas operator also of Midland, Texas during the early part of 1984. Mr. Coggin taught public school for four years prior to his business experience. Mr. Coggin received a B.S. in Education and a B.B.A. in Accounting from Angelo State University.
Richard E. Masterson, Vice President, Exploration and Acquisitions, first became associated with the Managing General Partner as a geological consultant in 1985. He was employed as a petroleum geologist by Grand Banks Energy (1980-1985), Monsanto (1977-1980) and Texaco, Inc. (1974-1976) prior to joining the Managing General Partner. Mr. Masterson is a member of the Society of Economic Paleontologists and Mineralogists and the West Texas Geological Society. Mr. Masterson received his B.A. degree in Geology from Trinity University.
Jon P. Tate, Vice President, Land and Assistant Secretary, assumed his responsibilities with the Managing General Partner in 1989. Prior to joining the Managing General Partner, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as Land Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin Landman's Association and received his B.B.S. degree from Hardin-Simmons University.
Joel D. Talley, Vice President, Acquisitions and Exploitation Manager, assumed his responsibilities with the Managing General Partner on July 15, 1996. Prior to joining the Managing General Partner, Mr. Talley was employed for four (4) years by Merit Energy Company as Acquisitions Manager and then as Region Manager over West Texas, New Mexico and Wyoming (1992-1996) and eight (8) years by ARCO Oil & Gas Company in various engineering positions (1984-1992). Mr. Talley received his B.S. in Mechanical Engineering in 1984 from Texas A&M University.
R. Douglas Keathley, Vice President, Operations, assumed his responsibilities with the Managing General Partner as a Production Engineer in October, 1992. Prior to joining the Managing General Partner, Mr. Keathley was employed for four (4) years by ARCO Oil & Gas Company as senior drilling engineer working in all phases of well production (1988-1992), eight (8) years by Reading & Bates Petroleum Company as senior petroleum engineer responsible for drilling (1980-1988) and two (2) years by Tenneco Oil Company as drilling engineer responsible for all phases of drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum Engineering in 1977 from the University of Oklahoma.
Key Employees
Accounting and Administrative Officer - Debbie A. Brock, age 44, assumed her position with the Managing General Partner in 1991. Prior to joining the Managing General Partner, Ms. Brock was employed with Western Container Corporation as Accounting Manager (1982-1990), Synthetic Industries (Texas), Inc. as Accounting Manager (1976-1982) and held various accounting positions in the manufacturing industry (1971-1975). Ms. Brock received a B.B.A. from the University of Houston.
Controller - Robert A. Langford, age 47, assumed his responsibilities with the Managing General Partner in 1992. Mr. Langford received his B.B.A. degree in Accounting in 1975 from the University of Central Arkansas. Prior to joining the Managing General Partner, Mr. Langford was employed with Forest Oil Corporation as Corporate Coordinator, Regional Coordinator, Accounting Manager. He held various other positions from 1982-1992 and 1976- 1980 and was Assistant Controller of National Oil Company from 1980-1982.
Financial Reporting Manager - Bryan Dixon, C.P.A., age 30, assumed his responsibilities with the Managing General Partner in 1992. Mr. Dixon received his B.B.A. degree in Accounting in 1988 from Texas Tech University in Lubbock, Texas. Prior to joining the Managing General Partner, Mr. Dixon was employed as a Senior Auditor with Johnson, Miller & Company from 1991- 1992 and Audit Supervisor for Texas Tech University and the Texas Tech University Health Sciences Center from 1988-1991.
Production Superintendent - Steve C. Garner, age 55, assumed his responsibilities with the Managing General Partner as Production Superintendent in July, 1989. Prior to joining the Managing General Partner, Mr. Garner was employed 16 years by Shell Oil Company working in all phases of oil field production as operations foreman, one and one-half years with Petroleum Corporation of Delaware as Production Superintendent, six years as an independent engineering consultant, and one year with Citation Oil & Gas Corp. as a workover, completion and production foreman. Mr. Garner has worked extensively in the Permian Basin oil field for the last 25 years.
Tax Manager - Carolyn Cookson, age 40, assumed her position with the Managing General Partner in April, 1989. Prior to joining the Managing General Partner, Ms. Cookson was employed as Director of Taxes at C.F. Lawrence & Associates, Inc. from 1983 to 1989, and worked in public accounting at McCleskey, Cook & Green, P.C. from 1981 to 1983 and Deanna Brady, C.P.A. from 1980 to 1981. She is a member of the Permian Basin Chapter of the Petroleum Accountants' Society, and serves on its Board of Directors and is liaison to the Tax Committee. Ms. Cookson received a B.B.A. in accounting from New Mexico State University.
Vice President, Marketing - Steve J. Person, age 38, joined the Managing General Partner in 1989. Prior to joining the Managing General Partner, Mr. Person served as Vice President of Marketing for CRI, Inc., and was associated with Capital Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor University in 1982 and an M.D.A. from Houston Baptist University in 1987.
Investor Relations Manager - Sandra K. Flournoy, age 50, came to Southwest Royalties, Inc. in 1988 from Parker & Parsley Petroleum, where she was Assistant Manager of Investor Services and Broker/Dealer Relations for two years. Prior to that, Ms. Flournoy was Administrative Assistant to the Superintendent at Greenwood ISD for four years.
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 $68,400 during 1996, 1995 and 1994 as an annual administrative fee for indirect general and administrative overhead expense.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no limited partners who own of record, or are known by the Managing General Partner to beneficially own, more than five percent of the Partnership's limited partnership interests.
The Managing General Partner owns a nine percent interest as a general partner. Through prior purchases, the Managing General Partner also owns 54 limited partner units, or a .55% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 9.5%.
No officer or director of the Managing General Partner owns Units in the Partnership. H. H. Wommack, III, as the individual general partner of the Partnership, owns a one percent interest as a general partner. The officers and directors of the Managing General Partner are considered beneficial owners of the limited partner units acquired by the Managing General Partner by virtue of their status as such. A list of beneficial owners of limited partner units, acquired by the Managing General Partner, is as follows:
Amount and Nature of Percent Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------------- --------------- ------- Limited Partnership Southwest Royalties, Inc. Directly Owns .55% Interest Managing General Partner 54 Units 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns .55% Interest Chairman of the Board, 54 Units President, CEO, Treasurer and Director of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. Allen Corey Indirectly Owns .55% Interest Secretary and Director of 54 Units Southwest Royalties, Inc., the Managing General Partner 633 Chestnut Street Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns .55% Interest Vice President and CFO of 54 Units Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership Richard E. Masterson Indirectly Owns .55% Interest Vice President, Exploration 54 Units and Acquisitions of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership Jon P. Tate Indirectly Owns .55% Interest Vice President, Land and 54 Units Assistant Secretary of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Amount and Nature of Percent Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------------- --------------- ------- Limited Partnership Joel D. Talley Indirectly Owns .55% Interest Vice President, 54 Units Acquisitions and Exploitation Manager of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership R. Douglas Keathley Indirectly Owns .55% Interest Vice President, Operations 54 Units 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 1996, the Managing General Partner received $68,400 as an administrative fee. This amount is part of the general and administrative expenses incurred by the Partnership.
In some instances the Managing General Partner and certain officers and employees may be working interest owners in an oil and gas property in which the Partnership also has a net profits interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $96,000 for administrative overhead attributable to operating such properties during 1996.
Certain subsidiaries of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $4,000 for the year ended December 31, 1996.
The law firm of Miller & Martin, of which H. Allen Corey, an officer and director of the Managing General Partner, is a partner, is counsel to the Partnership. Legal services rendered by Miller & Martin to the Partnership during 1996 were approximately $100 which constitutes an immaterial portion of that firm's business. Subsequent to December 31, 1996, the counsel to the Partnership, H. Allen Corey, became a partner in the law firm Baker, Donelson, Bearman & Caldwell.
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 --
Report of Independent Accountants 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 Royalties Institutional Income Fund IX-B, 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 Royalties Institutional Income Fund IX-B, L.P. dated September 26, 1989. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1989.)
27 Financial Data Schedule
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the quarter ended December 31, 1996.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Royalties Institutional Income Fund IX-B, 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 26, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III ----------------------------------- H. H. Wommack, III, Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
Date: March 26, 1997
By: /s/ H. Allen Corey ----------------------------- H. Allen Corey, Secretary and Director
Date: March 26, 1997