FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [Fee Required]
For the fiscal year ended December 31, 1998
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required]
For the transition period from to
Commission File Number 33-47668-02
Southwest Royalties Institutional Income Fund XI-B, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2427289
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300, Midland, Texas 79701
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (915) 686-9927
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
limited partnership interests
Indicate by check mark whether registrant (1) has filed reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [x]
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is __. There is no
exhibit index.
<PAGE>
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 6
3. Legal Proceedings 9
4. Submission of Matters to a Vote of Security Holders 9
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 10
6. Selected Financial Data 11
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 12
8. Financial Statements and Supplementary Data 21
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 38
Part III
10. Directors and Executive Officers of the Registrant 39
11. Executive Compensation 42
12. Security Ownership of Certain Beneficial Owners and
Management 42
13. Certain Relationships and Related Transactions 43
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 44
Signatures 45
<PAGE>
Part I
Item 1. Business
General
Southwest Royalties Institutional Income Fund XI-B, L.P. (the "Partnership"
or "Registrant") was organized as a Delaware limited partnership on August
31, 1993. The offering of limited partnership interests began October 25,
1993, as part of a shelf offering registered under the name Southwest
Royalties Institutional 1992-93 Income Program. Minimum capital
requirements for the Partnership were met on December 8, 1993 and concluded
August 20, 1994. The Partnership has no subsidiaries.
As of December 31, 1996, the Partnership had utilized approximately
$2,008,600 of limited partner capital contributions to acquire interests in
oil and gas properties. All excess capital, $89,489, and the associated
organization costs of $3,132, has been distributed to the limited partners
in proportion to their capital contributions as a return of capital.
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 98 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 interest and net profit
interests in oil and gas properties located in New Mexico and Texas. All
activities of the Partnership are confined to the continental United
States. All oil and gas produced from these properties is sold to
unrelated third parties in the oil and gas business.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. With some periodic
exceptions, since the early 1980's, there has been a worldwide oversupply
of oil; therefore, market prices have declined significantly. 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 for
oil and natural gas.
<PAGE>
During 1998 oil prices fell to their lowest daily levels since 1986 and to
their lowest annual average since 1976. In two years, oil prices have been
sliced by more than half. The factors that started the decline in oil
prices in 1997 are the same ones that have kept them down in 1998. It was
believed that there would be continued heavy consumption coming from the
Asian region, but the collapse of their markets late in 1997 carried over
to this year bringing demand down with it. Asian consumption had all but
disappeared in 1998, creating an oversupply of crude oil on the market.
That drop in demand has lasted longer than anyone had anticipated, but
hopes of a recovery abound. Another reason for the continued drop in
prices has been OPEC's unwillingness to completely comply with production
cuts established in March and again in June. Although they have been near
90% compliance at times, they have also been below 70% on a monthly basis.
Even a four-day bombing in December of Iraqi military sites could create
only a one-day rally in oil prices. Crude oil closed December 31, 1998 at
$12.05 per barrel on the NYMEX and posted prices closed at $9.50 per
barrel.
In a year of fairly optimistic expectations for gas prices, the average
price of natural gas wound up declining in 1998 to its lowest level since
1995. Although the nationwide average did remain above $2.00 per MMBTU,
1998's prices were approximately 17% lower than those seen in 1997. The
combination of mild weather throughout the year and a gas storage surplus
both contributed to the low prices. Analysts' predictions for 1999 prices
vary, ranging from a low of $1.87 per MMBTU to a high of $2.40 per MMBTU.
Reduced production throughout the U.S. industry, along with large gas
storage withdrawals during the first weeks of January 1999, are both key
factors in our belief that the 1999 average gas price will remain around
$1.80 per MMBTU level.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
1998 46% 54%
1997 48% 52%
1996 53% 47%
As the table indicates, the Partnership's revenue is almost evenly divided
between its oil and gas 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 volume sold by the Partnership is not expected to fluctuate
materially with the change of season.
Customer Dependence
No material portion of the Partnership's business is dependent on a single
purchaser, or a very few purchasers, where the loss of one would have a
material adverse impact on the Partnership. Two purchasers accounted for
72% of the Partnership's total oil and gas production during 1998: Navajo
Refining Company for 39% and American Processing for 33%. Two purchasers
accounted for 71% of the Partnership's total oil and gas production during
1997: Navajo Refining Company, Inc. for 36%, and American Processing for
35%. Two purchasers accounted for 69% of the Partnership's total oil and
gas production during 1996: Navajo Refining Company, Inc. 41%, and
American Processing 28%.
<PAGE>
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 will be 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.
<PAGE>
Environmental - The Partnership's oil and gas activities will be 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,
1998 there were 98 individuals directly employed by the Managing General
Partner in various capacities.
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, 1998, the Partnership possessed an interest in oil and
gas properties located in Eddy County of New Mexico; Andrews, Dawson,
Howard, Midland, Reeves, Schleicher, Stonewall, Upton, Ward and Winkler
Counties of Texas. These properties consist of various interests in 77
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 1998, 1997 and 1996.
During 1998, five leases were sold for approximately $600.
<PAGE>
In compliance with the Partnership Agreement, if the Partnership should
purchase a producing property from the Managing General Partner, such
purchase price would be prior cost, adjusted for any intervening operation.
If such adjusted cost was greater than fair market value, or if specific
cost was unable to be determined, such purchase price would be fair market
value as determined by an independent reservoir engineer.
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)
- ----------------- ------------ ------ --------- ---------
Custer & Wright 11/94 at 28 7,000 467,000
Winkler County, 1% to 40%
Texas net profits
interests
Michael Dingman 9/94 at 42 15,000 95,000
Midland, Stonewall, .5% to 50%
Reeves, Dawson, net profits
Schleicher, Winkler interests
Ward, Andrews, Counties,
Texas: Eddy County,
New Mexico
<PAGE>
*Ryder Scott Company Petroleum Engineers prepared the reserve and present
value data for 96.4% of the Partnership's existing properties as of January
1, 1999. Another independent petroleum engineer prepared the remaining
3.6% of the Partnership's properties. 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 to be prepared under existing economic
and operating conditions with no provisions for price and cost escalation
except by contractual arrangements.
The New York Mercantile Exchange price at December 31, 1998 of $12.50 was
used as the beginning basis for the oil price. Oil price adjustments from
$12.50 per barrel were made in the individual evaluations to reflect oil
quality, gathering and transportation costs. The results are an average
price received at the lease of $10.26 per barrel in the preparation of the
reserve report as of January 1, 1999.
In the determination of the gas price, the New York Mercantile Exchange
price at December 31, 1998 of $1.95 was used as the beginning basis. Gas
price adjustments from $1.95 per Mcf were made in the individual
evaluations to reflect BTU content, gathering and transportation costs and
gas processing and shrinkage. The results are an average price received at
the lease of $1.43 per Mcf in the preparation of the reserve report as of
January 1, 1999.
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 1998.
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.
<PAGE>
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 farmout
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 farmout, 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 Operation.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
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 1998 through the solicitation of proxies or otherwise.
<PAGE>
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters
Market Information
Limited partnership interests, or units, in the Partnership are currently
being 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. 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, 1998, 1997 and 1996, no limited partner units were purchased
by the Managing General Partner.
Number of Limited Partner Interest Holders
As of December 31, 1998, there were 176 holders of limited partner units in
the Partnership.
Distributions
Pursuant to Article III, Section 3.05 of the Partnership's Certificate and
Agreement of Limited Partnership, "Net Cash Flow" shall be 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) Direct Costs,
(iii) Operating Costs, and (iv) any reserves necessary to meet current and
anticipated needs of the Partnership, as determined in the sole discretion
of the Managing General Partner."
<PAGE>
During 1998, distributions were made totaling $58,500, with $52,650
distributed to the limited partners and $5,850 to the general partners.
For the year ended December 31, 1998, distributions of $10.85 per limited
partner unit were made, based upon 4,851 limited partner units outstanding.
The decline in distributions experienced in 1998 will be expected to
continue into 1999 based on the continued low oil price economy. During
1997, twelve monthly distributions were made totaling $300,600, with
$270,540 distributed to the limited partners and $30,060 to the general
partners. For the year ended December 31, 1997, distributions of $55.77
per limited partner unit were made, based upon 4,851 limited partner units
outstanding. During 1996, twelve monthly distributions were made totaling
$338,739, with $314,239 distributed to the limited partners and $24,500 to
the general partners. For the year ended December 31, 1996, distributions
of $64.78 per limited partner unit were made, based upon 4,851 limited
partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31 1998,
1997, 1996, 1995 and 1994 should be read in conjunction with the financial
statements included in Item 8:
Years ended
December 31,
----------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Revenues $ 2,205 304,410 395,095 251,501 150,925
Net income (loss) (462,692) (467,687) 180,841 (99,700) 87,328
Partners' share of
net income (loss):
General partners (4,630) 25,491 34,555 19,946 10,522
Limited partners (458,062) (493,178) 146,286(119,646) 76,806
Limited partners' net
income (loss) per unit (94.43) (101.67) 30.16 (24.66)
15.83
Limited partner's cash
distribution per unit 10.85 55.77 64.78 45.14
9.89
Total assets $ 388,507 909,626 1,677,9071,835,8342,184,955
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized as a
Delaware limited partnership on August 31, 1993. The offering of limited
partnership interests began October 25, 1993, as part of a shelf offering
registered under the name Southwest Royalties Institutional 1992-93 Income
Program. Minimum capital requirements for the Partnership were met on
December 8, 1993, and the Offering Period terminated August 20, 1994 with
174 limited partners purchasing 4,851 units for $2,425,500.
The Partnership was formed to acquire non-operating interests in producing
oil and gas properties, to produce and market crude oil and natural gas
produced from such properties and to distribute any net proceeds from
operations to the general and limited partners. Net revenues from
producing oil and gas properties will not be 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 will thus depend 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 farmout arrangements and on the depletion wells. Since wells
deplete over time, production can generally be expected to decline from
year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the limited
partners has fluctuated over the past few years and is expected to
fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing no workovers
during 1999 to enhance production. With expected price improvement,
workovers may be performed in the year 2001. The partnership may have an
increase in the year 2001, otherwise, the Partnership will most likely
experience it's historical decline of approximately 14% per year.
<PAGE>
Results of Operations
A. General Comparison of the Years Ended December 31, 1998 and 1997
The following table provides certain information regarding performance
factors for the years ended December 31, 1998 and 1997:
Year Ended Percentage
December 31, Increase
1998 1997 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 11.68 19.37 (40%)
Average price per mcf of gas $ 1.52 2.22 (32%)
Oil production in barrels 9,800 11,400 (14%)
Gas production in mcf 87,300 109,000 (20%)
Income from net profits interests $ 31,907 206,956 (85%)
Partnership distributions $ 58,500 300,600 (81%)
Limited partner distributions $ 52,650 270,540 (81%)
Per unit distribution to limited partners $ 10.85 55.77 (81%)
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests decreased to $31,907
from $206,956 for the years ended December 31, 1998 and 1997, respectively,
a decrease of 85%. The principal factors affecting the comparison of the
years ended December 31, 1998 and 1997 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 1998 as compared to the
year ended December 31, 1997 by 40%, or $7.69 per barrel, resulting in
a decrease of approximately $87,700 in income from net profits
interests. Oil sales represented 46% of total oil and gas sales during
the year ended December 31, 1998 as compared to 48% during the year
ended December 31, 1997.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 32%, or $.70 per mcf, resulting in
a decrease of approximately $76,300 in income from net profits
interests.
The total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$164,000. 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.
<PAGE>
2. Oil production decreased approximately 1,600 barrels or 14% during the
year ended December 31, 1998 as compared to the year ended December 31,
1997, resulting in a decrease of approximately $18,700 in income from
net profits interests.
Gas production decreased approximately 21,700 mcf or 20% during the
same period, resulting in a decrease of approximately $33,000 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $51,700. The decrease in oil and
gas production is primarily due to property sales and a gas plant
explosion which stopped production in March and April of 1998.
3. Lease operating costs and production taxes were 16% lower, or
approximately $41,000 less during the year ended December 31, 1998 as
compared to the year ended December 31, 1997. The decrease in lease
operating costs are primarily in relation to property sales.
4. As of December 31, 1998, miscellaneous expense was approximately
$30,159. The Partnership entered into a purchase agreement on the Tar
Baby lease that guaranteed net income each month from October 1994
through January 1998. This income was recorded on the Partnerships
books as miscellaneous income. Based on new information obtained in
May 1998, an adjustment of $52,706 was found to be necessary. This
adjustment was recorded as miscellaneous expense on the Partnerships
books for the quarter ended June 30, 1998.
Costs and Expenses
Total costs and expenses decreased to $464,897 from $772,097 for the years
ended December 31, 1998 and 1997, respectively, a decrease of 40%. The
decrease is the result of lower depletion expense, provision for impairment
and general and administrative costs.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased 2%
or approximately $1,000 during the year ended December 31, 1998 as
compared to the year ended December 31, 1997.
2. Depletion expense decreased to $130,000 for the year ended December
31, 1998 from $226,000 for the same period in 1997. This represents a
decrease of 42%. 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 decrease 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, 1998 as compared
to 1997. 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 increased depletion expense approximately $30,000 as of
December 31, 1997.
The Partnership reduced the net capitalized costs of oil and gas
properties in 1998 by approximately $279,567. The write-down has the
effect of reducing net income, but did not affect cash flow or partner
distributions.
<PAGE>
Results of Operations
B. General Comparison of the Years Ended December 31, 1997 and 1996
The following table provides certain information regarding performance
factors for the years ended December 31, 1997 and 1996:
Year Ended Percentage
December 31, Increase
1997 1996 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 19.37 20.65 (6%)
Average price per mcf of gas $ 2.22 2.15 3%
Oil production in barrels 11,400 15,400 (26%)
Gas production in mcf 109,000 133,300 (18%)
Income from net profits interests $ 206,956 315,055 (34%)
Partnership distributions $ 300,600 338,739 (11%)
Limited partner distributions $ 270,540 314,239 (14%)
Per unit distribution to limited partners $ 55.77 64.78 (14%)
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests decreased to $206,956
from $315,055 for the years ended December 31, 1997 and 1996, respectively,
a decrease of 34%. The principal factors affecting the comparison of the
years ended December 31, 1997 and 1996 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 1997 as compared to the
year ended December 31, 1996 by 6%, or $1.28 per barrel, resulting in a
decrease of approximately $19,700 in income from net profits interests.
Oil sales represented 48% of total oil and gas sales during the year
ended December 31, 1997 as compared to 53% during the year ended
December 31, 1996.
The average price for an mcf of gas received by the Partnership
increased during the same period by 3%, or $.07 per mcf, resulting in
an increase of approximately $9,300 in income from net profits
interests.
The net total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$10,400 . 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.
<PAGE>
2. Oil production decreased approximately 4,000 barrels or 26% during the
year ended December 31, 1997 as compared to the year ended December 31,
1996, resulting in a decrease of approximately $77,500 in income from
net profits interests.
Gas production decreased approximately 24,300 mcf or 18% during the
same period, resulting in a decrease of approximately $53,900 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $131,400. The decrease in
production is primarily attributable to downtime experienced on two
wells, one well being shut-in and normal decline.
3. Lease operating costs and production taxes were 12% lower, or
approximately $33,300 less during the year ended December 31, 1997 as
compared to the year ended December 31, 1996. Decrease is due
primarily to pulling expense incurred on one well in 1996 and post
closing costs recorded in 1996 on the purchase of the Kaiser State #44.
4. As of December 31, 1997, miscellaneous income was approximately
$94,424. The income is a result of a purchase agreement, on the Tar
Baby lease, that guarantees the Partnership a net income of
approximately $3,400 each month from October 1994 to January 1998.
Costs and Expenses
Total costs and expenses increased to $772,097 from $214,254 for the years
ended December 31, 1997 and 1996, respectively, an increase of 260%. The
increase is the result of higher depletion expense and a provision for
impairment of oil and gas properties.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 2%
or approximately $800 during the year ended December 31, 1997 as
compared to the year ended December 31, 1996.
3. Depletion expense increased to $226,000 for the year ended December
31, 1997 from $158,000 for the same period in 1996. This represents an
increase of 43%. 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 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, 1998 as compared
to 1997. 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 increased depletion expense approximately $98,000 as of
December 31, 1996.
The Partnership reduced the net capitalized costs of oil and gas
properties in 1997 by approximately $489,154. The write-down has the
effect of reducing net income, but did not affect cash flow or partner
distributions.
<PAGE>
C. Revenue and Distribution Comparison
Partnership income or (loss) for the years ended December 31, 1998, 1997
and 1996 was $(462,692), $(467,687) and $180,841, respectively. Excluding
the effects of depreciation, depletion, amortization and provision for
impairment, net income (loss) would have been $(46,305) in 1998, $254,907
in 1997 and $346,439 in 1996. Correspondingly, Partnership distributions
for the years ended December 31, 1998, 1997 and 1996 were $58,500, $300,600
and $338,739, respectively. These differences are indicative of the
changes in oil and gas prices, production and property.
The source for the 1998 distributions of $58,500 were oil and gas
operations of approximately $55,200, and the change in oil and gas
properties of approximately $600, with the balance from available cash on
hand at the beginning of the period. The source for the 1997 distributions
of $300,600 were oil and gas operations of approximately $285,200, with the
balance from available cash on hand at the beginning of the period. The
sources for the 1996 distributions of $338,739 were oil and gas operations
of approximately $259,900, the refund of organization cost of approximately
$3,100 and excess capital of approximately $89,500, resulting in excess
cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 1998 were $58,500 of
which $52,650 was distributed to the limited partners and $5,850 to the
general partners. The per unit distribution to limited partners during the
same period was $10.85. Total distributions during the year ended December
31, 1997 were $300,600 of which $270,540 was distributed to the limited
partners and $30,060 to the general partners. The per unit distribution to
limited partners during the same period was $55.77. Total distributions
during the year ended December 31, 1996 were $338,739 of which $314,239 was
distributed to the limited partners and $24,500 to the general partners.
The per unit distribution to limited partners during the same period was
$64.78.
Since inception of the Partnership, cumulative monthly cash contributions
of $989,439 have been made to the partners. As of December 31,1998
$904,353 or $186.43 per limited partner unit, has been distributed to the
limited partners, representing a 37% return of the capital contributed.
<PAGE>
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
net profits interests in oil and gas properties. The Partnership knows of
no material change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $55,200 in
1998 compared to $285,200 in 1997 and approximately $259,900 in 1996. The
primary source of the 1998 cash flow from operating activities was
profitable operations.
Cash flows from investing activities were approximately $600 in 1998. The
Partnership had no cash flows from investing activities in 1997. Cash
flows from investing activities were approximately $3,100 in 1996.
Cash flows used in financing activities were approximately $58,400 in 1998
compared to $300,500 in 1997 and approximately $338,800 in 1996. The only
1998 use in financing activities was the distribution to partners.
As of December 31, 1998, the Partnership had approximately $7,100 in
working capital. The Managing General Partner knows of no other
commitments and believes the revenues generated from operations will be
adequate to meet the operating needs of the Partnership.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
over $21.0 million of interest payments due in 1999 on its debt
obligations. Due to severely depressed commodity prices, the Managing
General Partner is experiencing difficulty in generating sufficient cash
flow to meet its obligations and sustain its operations. The Managing
General Partner is currently in the process of renegotiating the terms of
its various obligations with its creditors and/or attempting to seek new
lenders or equity investors. Additionally, the Managing General Partner
would consider disposing of certain assets in order to meet its
obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the lenders will agree to
a course of action consistent with the Managing General Partners
requirements in restructuring the obligations. Even if such agreement is
reached, it may require approval of additional lenders, which is not
assured. Furthermore, there can be no assurance that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Under current circumstances, the Managing General
Partner's ability to continue as a going concern depends upon its ability
to (1) successfully restructure its obligations or obtain additional
financing as may be required, (2) maintain compliance with all debt
covenants, (3) generate sufficient cash flow to meet its obligations on a
timely basis, and (4) achieve satisfactory levels of future earnings. If
the Managing General Partner is unsuccessful in its efforts, it may be
unable to meet its obligations making it necessary to undertake such other
actions as may be appropriate to preserve asset values.
Information Systems for the Year 2000
The Managing General Partner provides all data processing needs of the
Partnership. The Managing General Partner is continuing in its effort to
identify and assess its exposure to the potential Year 2000 software and
imbedded chip processing and date sensitivity issue. Through the Managing
General Partners data processing subsidiary, Midland Southwest Software,
Inc., the Managing General Partner proactively initiated a plan to identify
applicable hardware and software, assess impact and effect, estimate costs,
construct and implement corrective actions, and prepare contingency plans.
<PAGE>
Identification & Assessment
The Managing General Partner currently believes it has identified the
internal and external software and hardware that may have date sensitivity
problems. Four critical systems and/or functions were identified: (1) the
proprietary software of the Partnership (OGAS) that is used for oil & gas
property management and financial accounting functions, (2) the DEC VAX/VMS
hardware and operating system, (3) various third-party application software
including lease economic analysis, fixed asset management, geological
applications, and payroll/human resource programs, and (4) External Agents.
The proprietary software of the Partnership is currently in process of
meeting compliance requirements with an estimated completion date of mid-
year 1999. Since this is an internally generated software package, the
Managing General Partner has estimated the cost to be approximately $25,000
by estimating the necessary man-hours. These modifications are being made
by internal staff and do not represent additional costs to the Partnership.
The Managing General Partner has not made contingency plans at this time
since the conversion is ahead of schedule and being handled by Managing
General Partner controlled internal programmers. Given the complexity of
the systems being modified, it is anticipated that some problems may arise,
but with an expected early completion date, the Managing General Partner
feels that adequate time is available to overcome unforeseen delays.
DEC has released a fully compliant version of its operating system that is
used by the Partnership on the DEC VAX system. It will be installed in
August 1999, the Managing General Partner believes that this will solve any
potential problems on the system.
The Managing General Partner has identified various third-party software
that may have date sensitivity problems and is working with the vendors to
secure solutions as well as prepare contingency plans. After review and
evaluation of the vendor plans and status, the Managing General Partner
believes that the problems will be resolved prior to the year 2000 or the
alternate contingency plan will sufficiently and adequately remediate the
problem so that there is no material disruption to business functions.
The External Agents of the Partnership include suppliers, customers,
owners, vendors, banks, product purchasers including pipelines, and other
oil and gas property operators. The Managing General Partner is in the
process of identifying and communicating with each critical External Agent
about its plan and progress thereof in addressing the Year 2000 issue.
This process is on schedule and the Managing General Partner, at this time,
believes that there should be no material interference or disruption
associated with any of the critical External Agent's functions necessary to
the Partnership's business. The Managing General Partner estimates
completion of this audit by mid-year 1999 and believes that alternate plans
can be devised to circumvent any material problems arising from critical
External Agent noncompliance.
Cost
To date, the Managing General Partner has incurred only minimal internal
man-hour costs for identification, planning, and maintenance. The Managing
General Partner believes that the necessary additional costs will also be
minimal and most will fall under normal and general maintenance procedures
and updates. An accurate cost cannot be determined at this time, but it is
expected that the total cost to remediate all systems to be less than
$50,000.
<PAGE>
Risks/Contingency
The failure to correct critical systems of the Partnership, or the failure
of a material business partner or External Agent to resolve critical Year
2000 issues could have a serious adverse impact on the ability of the
Partnership to continue operations and meet obligations. Based on the
Managing General Partner's evaluation and assessment to date, it is
believed that any interruption in operation will be minor and short-lived
and pose no material monetary loss, safety, or environmental risk to the
Partnership. However, until all assessment is complete, it is impossible
to accurately identify the risks, quantify potential impacts or establish a
final contingency plan. The Managing General Partner believes that its
assessment and contingency planning will be complete no later than mid-year
1999.
Worst Case Scenario
The Securities and Exchange Commission requires that public companies must
forecast the most reasonably likely worst case Year 2000 scenario, assuming
that the Managing General Partner's Year 2000 plan is not effective.
Analysis of the most reasonably likely worst case Year 2000 scenarios the
Partnership may face leads to contemplation of the following possibilities
which, though considered highly unlikely, must be included in any
consideration of worst cases: widespread failure of electrical, gas, and
similar supplies by utilities serving the Partnership; widespread
disruption of the services of communications common carriers; similar
disruption to means and modes of transportation for the Partnership and its
employees, contractors, suppliers, and customers; significant disruption to
the Partnership's ability to gain access to, and continue working in,
office buildings and other facilities; and the failure, of third-parties
systems, the effects of which would have a cumulative material adverse
impact on the Partnership's critical systems. The Partnership could
experience an inability by customers, traders, and others to pay, on a
timely basis or at all, obligations owed to the Partnership. Under these
circumstances, the adverse effect on the Partnership, and the diminution of
Partnership revenues, could be material, although not quantifiable at this
time.
<PAGE>
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Independent Auditors Reports 22
Balance Sheets 24
Statements of Operations 25
Statements of Changes in Partners' Equity 26
Statements of Cash Flows 27
Notes to Financial Statements 29
<PAGE>
INDEPENDENT AUDITORS REPORT
The Partners
Southwest Royalties Institutional
Income Fund XI-B, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Royalties
Institutional Income Fund XI-B, L.P. (the "Partnership") as of December 31,
1998 and 1997, and the related statements of operations, changes in
partners' equity and cash flows for the years then ended. 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 XI-B, L.P. as of December 31, 1998 and 1997 and
the results of its operations and its cash flows for the years then ended
in conformity with generally accepted accounting principles.
KPMG LLP
Midland, Texas
March 18, 1999
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners
Southwest Royalties Institutional
Income Fund XI-B, L.P.
Midland, Texas
We have audited the accompanying statements of operations, changes in
partners' equity and cash flows of Southwest Royalties Institutional Income
Fund XI-B, L.P. for the year 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 audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the statements of operations,
changes in partners equity and cash flows are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the statements of operations,
changes in partners equity and cash flows. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the
statements of operations, changes in partners equity and cash flows. We
believe that our audit of the statements of operations, changes in partners
equity and cash flows provides a reasonable basis for our opinion.
In our opinion, the statements of operations, changes in partners equity
and cash flows referred to above present fairly, in all material respects,
the results of operations and cash flows of Southwest Royalties
Institutional Income Fund XI-B, L.P. for the year 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
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 1998 and 1997
1998 1997
---- ----
Assets
Current assets:
Cash and cash equivalents $ 2,410 4,948
Receivable from Managing General Partner 4,796 54,454
Other receivable - 51,887
- --------- ---------
Total current assets
7,206 111,289
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 2,007,920 2,008,569
Less accumulated depreciation,
depletion and amortization
1,626,721 1,217,154
- --------- ---------
Net oil and gas properties
381,199 791,415
- --------- ---------
Organization costs, net of amortization
of $37,200 in 1998 and $30,380 in 1997 102 6,922
- --------- ---------
$
388,507 909,626
========= =========
Liabilities and Partners' Equity
Current liabilities:
Distribution payable $ 79 6
- --------- ---------
Partners' equity:
General partners 797 11,278
Limited partners 387,631 898,342
- --------- ---------
Total partners' equity
388,428 909,620
- --------- ---------
$
388,507 909,626
========= =========
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Operations
Years ended December 31, 1998, 1997 and 1996
1998 1997 1996
---- ---- ----
Revenues
Income from net profits interests $ 31,907 206,956 315,055
Interest income from capital contributions - -
895
Interest from operations 457 3,030 1,476
Miscellaneous income (30,159) 94,424 77,669
-------
- ------- -------
2,205
304,410 395,095
-------
- ------- -------
Expenses
General and administrative 48,510 49,503 48,656
Depreciation, depletion and amortization 136,820 233,440 165,598
Provision for impairment of oil and gas
properties 279,567 489,154 -
-------
- ------- -------
464,897
772,097 214,254
-------
- ------- -------
Net income (loss) $ (462,692) (467,687) 180,841
=======
======= =======
Net income (loss)allocated to:
Managing General Partner $ (4,168) 22,942 31,099
=======
======= =======
General Partner $ (463) 2,549 3,456
=======
======= =======
Limited partners $ (458,061) (493,178) 146,286
=======
======= =======
Per limited partner unit $ (94.43) (101.67) 30.16
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Changes in Partners' Equity
Years ended December 31, 1998, 1997 and 1996
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, 1995 $ 5,792 1,830,0131,835,805
Net income 34,555 146,286 180,841
Distributions (24,500) (314,239)(338,739)
-------
- --------- ---------
Balance at December 31, 1996 15,847 1,662,0601,677,907
Net income (loss) 25,491 (493,178)(467,687)
Distributions (30,060) (270,540)(300,600)
-------
- --------- ---------
Balance at December 31, 1997 11,278 898,342 909,620
Net income (loss) (4,631) (458,061)(462,692)
Distributions (5,850) (52,650) (58,500)
-------
- --------- ---------
Balance at December 31, 1998 $ 797 387,631 388,428
=======
========= =========
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 1998, 1997 and 1996
1998 1997 1996
---- ---- ----
Cash flows from operating activities:
Cash received from net profits interests $ 78,812 331,720 306,153
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(24,029) (49,503)(48,656)
Interest received 457 3,030 2,371
--------
- -------- ----------
Net cash provided by operating activities 55,240 285,247
259,868
--------
- -------- ----------
Cash flows from investing activities:
Organization costs - - 3,132
Sales of oil and gas properties 649 - -
--------
- -------- ----------
Net cash provided by investing
activities 649 -
3,132
--------
- -------- ----------
Cash flows from financing activities:
Distributions to partners (58,427) (300,524)(338,838)
--------
- -------- ----------
Net decrease in cash and cash equivalents (2,538) (15,277) (75,838)
Beginning of period 4,948 20,225 96,063
--------
- -------- ----------
End of period $ 2,410 4,948 20,225
========
======== ==========
(continued)
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows, continued
Years ended December 31, 1998, 1997 and 1996
1998 1997 1996
---- ---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities:
Net income (loss) $ (462,692) (467,687) 180,841
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 136,820 233,440
165,598
(Increase) decrease in receivables 46,905 30,339 (86,571)
Increase in payables 54,640 - -
Provision for impairment of oil and gas
properties 279,567 489,154
- -
-------
- ------- -------
Net cash provided by operating activities $ 55,240 285,247 259,868
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized
under the laws of the state of Delaware on August 31, 1993, 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 will sell 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. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partner Partners (1)
------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital
contributions 100% -
Oil and gas revenues 90% 10%
All other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to the Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. Gain or loss on
the sale of oil and gas properties is not recognized unless
significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization
of oil and gas properties is computed under the units of revenue
method. Under the units of revenue method, depreciation, depletion
and amortization is computed on the basis of current gross revenues
from production in relation to future gross revenues, based on current
prices, from estimated production of proved oil and gas reserves.
Under the units of revenue method, the Partnership computes the
provision by multiplying the total unamortized cost of oil and gas
properties by an overall rate determined by dividing (a) oil and gas
revenues during the period by (b) the total future gross oil and gas
revenues as estimated by the Partnership's independent petroleum
consultants. It is reasonably possible that those estimates of
anticipated future gross revenues, the remaining estimated economic
life of the product, or both could be changed significantly in the
near term due to the potential fluctuation of oil and gas prices or
production. The depletion estimate would also be affected by this
change.
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. The Partnership reduced the net
capitalized costs of oil and gas properties in 1998 by approximately
$279,567. This write-down has the effect of reducing net income, but
did not affect cash flow or partnership distributions. As of December
31, 1996, the net capitalized costs did not exceed the estimated 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.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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.
Organization Costs
Organization costs are stated at cost and are amortized over sixty
months using the straight-line method.
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, 1998, 1997 and
1996, there were no significant amounts of imbalance in terms of units
and value.
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," the
Partnership's tax basis in its oil and gas properties at December 31,
1998 and 1997 is $558,051 more and $306,929 less than that shown on
the accompanying Balance Sheet in accordance with generally accepted
accounting principles.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, 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, 1998, 1997 and 1996 there were 4,851 limited
partner units outstanding held by 176 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.
3. Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure
with over $21.0 million of interest payments due in 1999 on its debt
obligations. Due to severely depressed commodity prices, the Managing
General Partner is experiencing difficulty in generating sufficient
cash flow to meet its obligations and sustain its operations. The
Managing General Partner is currently in the process of renegotiating
the terms of its various obligations with its creditors and/or
attempting to seek new lenders or equity investors. Additionally, the
Managing General Partner would consider disposing of certain assets in
order to meet its obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the lenders will
agree to a course of action consistent with the Managing General
Partners requirements in restructuring the obligations. Even if such
agreement is reached, it may require approval of additional lenders,
which is not assured. Furthermore, there can be no assurance that the
sales of assets can be successfully accomplished on terms acceptable
to the Managing General Partner. Under current circumstances, the
Managing General Partner's ability to continue as a going concern
depends upon its ability to (1) successfully restructure its
obligations or obtain additional financing as may be required, (2)
maintain compliance with all debt covenants, (3) generate sufficient
cash flow to meet its obligations on a timely basis, and (4) achieve
satisfactory levels of future earnings. If the Managing General
Partner is unsuccessful in its efforts, it may be unable to meet its
obligations making it necessary to undertake such other actions as may
be appropriate to preserve asset values.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
shall be further reduced by a risk factor discount of no more than one-
third (1/3) to be determined by the Managing General Partner in its
sole and absolute discretion.
The Partnership is subject to various federal, state and local
environmental laws and regulations which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 1998, the Partnership has not been fined, cited or
notified of any environmental violations and management is not aware
of any unasserted violations which would have a material adverse
effect upon capital expenditures, earnings or the competitive position
in the oil and gas industry. However, the Managing General Partner
does recognize by the very nature of its business, material costs
could be incurred in the near term to bring the Partnership into total
compliance. The amount of such future expenditures is not reliably
determinable due to several factors, including the unknown magnitude
of possible contaminations, the unknown timing and extent of the
corrective actions which may be required, the determination of the
Partnership's liability in proportion to other responsible parties and
the extent to which such expenditures are recoverable from insurance
or indemnifications from prior owners of Partnership's properties.
<PAGE>
Southwest Royalties Institutional Income Fund XI-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 $54,700, $56,000 and $57,200 for the years
ended December 31, 1998, 1997 and 1996, respectively. In addition,
the Managing General Partner and certain officers and employees may
have an interest in some of the properties that the Partnership also
participates.
Certain subsidiaries or affiliates of the Managing General Partner
perform various oilfield services for properties in which the
Partnership owns an interest. Such services aggregated approximately
$600, $700 and $3,000 for the years ended December 31, 1998, 1997 and
1996, 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
$33,711 in 1998, $42,000 during 1997 and 40,896 during 1996, as an
administrative fee for indirect general and administrative overhead
expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $4,796 and $54,454 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 1998 and 1997, 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. There were no legal services for the years ended
December 31, 1998 and 1997. As of December 31, 1996 there were
approximately $90 in legal services.
6. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchasers, where the loss of one
would have a material adverse impact on the Partnership. Two
purchasers accounted for 72% of the Partnership's total oil and gas
production during 1998: Navajo Refining Company for 39% and American
Processing for 33%. Two purchasers accounted for 71% of the
Partnership's total oil and gas production during 1997: Navajo
Refining Company, Inc. 36%, and American Processing 35%. Two
purchasers accounted for 69% of the Partnership's total oil and gas
production during 1996: Navajo Refining Company, Inc. 41%, and
American Processing 28%. 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.
<PAGE>
Southwest Royalties Institutional Income Fund XI-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, 1996 131,000 1,467,000
Revisions of previous estimates 13,000 113,000
Production (15,000) (133,000)
------- ---------
December 31, 1996 129,000 1,447,000
Revisions of previous estimates (60,000) (552,000)
Production (11,000) (109,000)
------- ---------
December 31, 1997 58,000 786,000
Sales of reserves in place (2,000) (1,000)
Revisions of previous estimates (24,000) (60,000)
Production (10,000) (87,000)
------- ---------
December 31, 1998 22,000 638,000
======= =========
Proved developed reserves -
December 31, 1996 122,000 1,428,000
======= =========
December 31, 1997 53,000 771,000
======= =========
December 31, 1998 22,000 626,000
======= =========
All of the Partnership's reserves are located within the continental
United States.
*Ryder Scott Company Petroleum Engineers prepared the reserve and
present value data for 96.4% of the Partnership's existing properties
as of January 1, 1999. Another independent petroleum engineer
prepared the remaining 3.6% of the Partnership's properties. 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
to be prepared under existing economic and operating conditions with
no provisions for price and cost escalation except by contractual
arrangements.
The New York Mercantile Exchange price at December 31, 1998 of $12.05
was used as the beginning basis for the oil price. Oil price
adjustments from $12.05 per barrel were made in the individual
evaluations to reflect oil quality, gathering and transportation
costs. The results are an average price received at the lease of
$10.25 per barrel in the preparation of the reserve report as of
January 1, 1999.
In the determination of the gas price, the New York Mercantile
Exchange price at December 31, 1998 of $1.95 was used as the beginning
basis. Gas price adjustments from $1.95 per Mcf were made in the
individual evaluations to reflect BTU content, gathering and
transportation costs and gas processing and shrinkage. The results
are an average price received at the lease of $1.43 per Mcf in the
preparation of
the reserve report as of January 1, 1999.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
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
farmout 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 farmout,
or receives cash.
<PAGE>
Southwest Royalties Institutional Income Fund XI-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, 1998, 1997 and 1996 is
presented below:
1998 1997 1996
---- ---- ----
Future cash inflows, net of
production and development
costs $ 593,000 1,104,000 4,409,000
10% annual discount for
estimated timing of cash
flows 212,000 313,000 1,692,000
--------- --------- ---------
Standardized measure of
discounted future net cash
flows $ 381,000 791,000 2,717,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
1998, 1997 and 1996 are as follows:
1998 1997 1996
---- ---- ----
Sales of oil and gas produced,
net of production costs $ (32,000) (207,000) (580,000)
Changes in prices and production costs (210,000)(1,560,000)
1,642,000
Changes of production rates
(timing) and others (135,000) 212,000 78,000
Revisions of previous
quantities estimates (103,000) (643,000) (357,000)
Accretion of discount 79,000 272,000 269,000
Discounted future net
cash flows -
Sales of minerals in place (9,000) - -
Beginning of year 791,000 2,717,000 1,665,000
--------- --------- ---------
End of year $ 381,000 791,000 2,717,000
========= ========= =========
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.
<PAGE>
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
On June 9, 1997 Southwest Royalties, Inc. the Partnership's Managing
General Partner (Southwest Royalties, Inc.) dismissed Joseph Decosimo and
Company as the Partnership's independent accountants. The Managing General
Partner's Board of Directors approved the decision to change the
Partnership's independent accountants.
The report of Joseph Decosimo and Company on the financial statements for
the fiscal year ended December 31, 1996 contained no adverse opinion or
disclaimer of opinion and was not qualified or modified as to uncertainty,
audit scope or accounting principle.
In connection with its audit for the fiscal year ended December 31, 1996
and through June 9, 1997, there have been no disagreements with Joseph
Decosimo and Company on any matter of accounting principles or practices,
financial statements disclosure, or auditing scope or procedure, which
disagreements if not resolved to the satisfaction of Joseph Decosimo and
Company would have caused them to make reference thereto in their report on
the financial statements for such year.
The Registrant has requested that Joseph Decosimo and Company furnish it
with a letter addressed to the SEC stating whether or not is agrees with
the above statements. A copy of that letter is included as Exhibit 16 and
has been filed with the Securities and Exchange Commission.
<PAGE>
Part III
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 43 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 42 Secretary and Director
Bill E. Coggin 44 Vice President and Chief
Financial Officer
Jon P. Tate 41 Vice President, Land and
Assistant Secretary
R. Douglas Keathley 43 Vice President, Operations
J. Steven Person 40 Vice President, Marketing
Paul L. Morris 57 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive
Officer, Treasurer, principal stockholder and a director of the Managing
General Partner, and has served as its President since the Company's
organization in August, 1983. Prior to the formation of the Company, Mr.
Wommack was a self-employed independent oil producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases,
and the drilling of exploratory and developmental oil and gas wells. Mr.
Wommack holds a J.D. degree from the University of Texas from which he
graduated in 1980, and a B.A. from the University of North Carolina in
1977.
H. Allen Corey, a founder of the Managing General Partner, has served as
the Managing General Partner's secretary and a director since its
inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew
pub restaurant chain based in the Southeast. Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga, Tennessee. He is currently of counsel to the law firm of
Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga,
Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University
Law School and B.A. degree from the University of North Carolina at Chapel
Hill.
<PAGE>
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.
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.
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.
J. Steven Person, Vice President, Marketing, assumed his responsibilities
with the Managing General Partner as National Marketing Director in 1989.
Prior to joining the Managing General Partner, Mr. Person served as Vice
President of Marketing for CRI, Inc., and was associated with Capital
Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor
University in 1982 and an M.D.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings,
Inc. since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States. Prior to
his position with Wagner & Brown, Mr. Morris served as President of Banner
Energy and in various managerial positions with Columbia Gas System, Inc.
<PAGE>
Key Employees
Accounting and Administrative Officer - Debbie A. Brock, age 46, 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 49, 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 32, 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 57, 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 42, 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.
<PAGE>
Investor Relations Manager - Sandra K. Flournoy, age 52, 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. 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 $33,711 during 1998, $42,000 during 1997 and $40,896 during 1996,
as an annual administrative fee.
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 in the
Partnership as a general partner.
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. 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.
<PAGE>
Item 13. Certain Relationships and Related Transactions
In 1998, the Managing General Partner received $33,711 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 $54,700 for administrative overhead
attributable to operating such properties during 1998.
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 $600 for the year ended
December 31, 1998.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
<PAGE>
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Reports of Independent Accountants
Balance Sheet
Statement of Operations
Statement of Changes in Partners' Equity
Statement 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 XI-B, L.P., dated August 24, 1993.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1993).
(b) Agreement of Limited
Partnership of Southwest Royalties Institutional
Income Fund XI-B, L.P., dated August 27, 1993.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1993).
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, 1998.
<PAGE>
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 XI-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 31, 1999
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 31, 1999
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 31, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Balance Sheet at December 31, 1998 and the Statement of Operations for
the Year Ended December 31, 1998 and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,410
<SECURITIES> 0
<RECEIVABLES> 4,796
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 7,206
<PP&E> 2,007,920
<DEPRECIATION> 1,626,721
<TOTAL-ASSETS> 388,507
<CURRENT-LIABILITIES> 79
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 388,428
<TOTAL-LIABILITY-AND-EQUITY> 388,507
<SALES> 31,907
<TOTAL-REVENUES> 2,205
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 464,897
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (462,692)
<INCOME-TAX> 0
<INCOME-CONTINUING> (462,692)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (462,692)
<EPS-PRIMARY> (94.43)
<EPS-DILUTED> (94.43)
</TABLE>
