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 33-47668-01
Southwest Royalties Institutional Income Fund XI-A, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2427297
(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 7
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 39
Part III
10. Directors and Executive Officers of the Registrant 40
11. Executive Compensation 43
12. Security Ownership of Certain Beneficial Owners and
Management 43
13. Certain Relationships and Related Transactions 46
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 47
Signatures 48
<PAGE>
Part I
Item 1. Business
General
Southwest Royalties Institutional Income Fund XI-A, L.P. (the "Partnership"
or "Registrant") was organized as a Delaware limited partnership on May 5,
1992. The offering of limited partnership interests began August 20, 1992,
as part of a shelf offering registered under the name Southwest Royalties
Institutional 1992-93 Income Program, reached minimum capital requirements
on December 10, 1992 and concluded April 30, 1993. The Partnership has no
subsidiaries.
The Partnership has acquired interests in producing oil and gas properties
and produced and marketed the crude oil and natural gas produced from such
properties. In most cases, the Partnership purchased royalty or overriding
royalty interests and working interests in oil and gas properties that were
converted into net profits interests or other non-operating interests. The
Partnership purchased either all or part of the rights and obligations
under various oil and gas leases.
The principal executive offices of the Partnership are located at 407 N.
Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner
of the Partnership, Southwest Royalties, Inc. (the "Managing General
Partner") and its staff of 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 interests and net profit
interests in oil and gas properties located in Alabama, Kansas, Louisiana,
New Mexico, Oklahoma and Texas. All activities of the Partnership are
confined to the continental United States. All oil and gas produced from
these properties is sold to unrelated third parties in the oil and gas
business.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. The prices received by
the Partnership for its oil and gas production depend upon numerous factors
beyond the Partnership's control, including competition, economic,
political and regulatory developments and competitive energy sources, and
make it particularly difficult to estimate future prices of oil and natural
gas.
<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 around the $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 39% 61%
1997 45% 55%
1996 48% 52%
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 volumes sold by the Partnership have not fluctuated materially
with the change of season.
<PAGE>
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. Four purchasers accounted for
63% of the Partnership's total oil and gas production during 1998:
American Processing for 22%, Nustar Joint Venture for 14%, Navajo Refining
Company, Inc. for 14% and Southwestern Energy Prod. Company for 13%. Two
purchasers accounted for 37% of the Partnership's total oil and gas
production during 1997: American Processing for 24%, and Navajo Refining
Company, Inc. for 13%. Three purchasers accounted for 47% of the
Partnership's total oil and gas production during 1996: American
Processing 20%, Navajo Refining Company, Inc. 14% and Torch Operating
Company 13%. All purchasers of the Partnership's oil and gas production
are unrelated third parties. In the event any of these purchasers were to
discontinue purchasing the Partnership's production, the Managing General
Partner believes that a substitute purchaser or purchasers could be located
without undue delay. No other purchaser accounted for an amount equal to
or greater than 10% of the Partnership's sales of oil and gas production.
Competition
Because the Partnership has utilized all of its funds available for the
acquisition of net profits or royalty interests in producing oil and gas
properties, it is not subject to competition from other oil and gas
property purchasers. See Item 2, Properties
Factors that may adversely affect the Partnership include delays in
completing arrangements for the sale of production, availability of a
market for production, rising operating costs of producing oil and gas and
complying with applicable water and air pollution control statutes,
increasing costs and difficulties of transportation, and marketing of
competitive fuels. Moreover, domestic oil and gas must compete with
imported oil and gas and with coal, atomic energy, hydroelectric power and
other forms of energy.
Regulation
Oil and Gas Production - The production and sale of oil and gas is subject
to federal and state governmental regulation in several respects, such as
existing price controls on natural gas and possible price controls on crude
oil, regulation of oil and gas production by state and local governmental
agencies, pollution and environmental controls and various other direct and
indirect regulation. Many jurisdictions have periodically imposed
limitations on oil and gas production by restricting the rate of flow for
oil and gas wells below their actual capacity to produce and by imposing
acreage limitations for the drilling of wells. The federal government has
the power to permit increases in the amount of oil imported from other
countries and to impose pollution control measures.
<PAGE>
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.
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 - 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 Escambia and Lamar Counties of Alabama; Labette
and Neosho Counties of Kansas; La Fourche, Pointe Coupe and Terrebonne
Parishes of Louisiana; Eddy County of New Mexico; Custer, Roger Mills and
Washita Counties of Oklahoma; and Dewitt, Dickens, Fayette, Gaines,
Hemphill, Howard, Live Oak, Reagan, Reeves, Upton, Ward, Winkler, and
Yoakum Counties of Texas. These properties consist of various interests in
102 wells and units.
Due to the Partnership's objective of maintaining current operations
without engaging in the drilling of any developmental or exploratory wells,
or additional acquisitions of producing properties, there have not been any
significant changes in properties during 1998 and 1997.
<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
operations. 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.
During 1998, fifty-five leases were sold for approximately $78,900. During
1997, four leases were sold for approximately $44,700. During 1996, four
leases were sold for approximately $6,200.
On October 15, 1998, Southwest Royalties Institutional Income Fund XI-A
(the "Registrant") sold its interest in 54 oil and gas properties to Parks
& Luttrell, Inc. ("Parks"), an unrelated party. The Registrant's interest
in the properties was sold for net proceeds, after post closing
adjustments, of $70,735. At December 31, 1997, the property sold to Parks
& Luttrell contained proved reserves of 27,531 barrels of oil and 113,835
mcfs of gas and had a SEC 10 value of $120,179 at the time of sale. The
proceeds from the sale represented 7.55% of the Registrant's total assets.
The General Partner sold the above properties and allocated the proceeds to
the Partnership based on current cash flows of the properties sold.
<PAGE>
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
Webb 5/94 at 4 14,000 4,000
Yoakum County, 12.5% net
Texas profits
interests
*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 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 $9.22 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 $1.48 per Mcf in the preparation of the reserve report as of
January 1, 1999.
As also discussed in Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations, oil prices were subject to
frequent changes in 1998.
<PAGE>
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly with
respect to the quantity of oil or gas that any given property is capable of
producing. Estimates of oil and gas reserves are based on available
geological and engineering data, the extent and quality of which may vary
in each case and, in certain instances, may prove to be inaccurate.
Consequently, properties may be depleted more rapidly than the geological
and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than
previously estimated; thus an ultimately lower return for the Partnership.
Basic changes in past reserve estimates occur annually. As new data is
gathered during the subsequent year, the engineer must revise his earlier
estimates. A year of new information, which is pertinent to the estimation
of future recoverable volumes, is available during the subsequent year
evaluation. In applying industry standards and procedures, the new data
may cause the previous estimates to be revised. This revision may increase
or decrease the earlier estimated volumes. Pertinent information gathered
during the year may include actual production and decline rates, production
from offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs, among
others. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing, proved developed non-producing and proved undeveloped. All of
the proved reserves are included in the engineering reports which evaluate
the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to farm-
out arrangements with the Managing General Partner or unrelated third
parties. Generally, the Partnership retains a carried interest such as an
overriding royalty interest under the terms of a farm-out, or receives
cash.
The Partnership or the owners of properties in which the Partnership owns
an interest can engage in workover projects or supplementary recovery
projects, for example, to extract behind the pipe reserves which qualify as
proved developed non-producing reserves. See Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Item 3. 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 were initially
offered and sold for a price of $500. Limited partner units are not traded
on any exchange and there is no public or organized trading market for
them. The Managing General Partner has become aware of certain limited and
sporadic transfers of units between limited partners and third parties, but
has no verifiable information regarding the prices at which such units have
been transferred. Further, a transferee may not become a substitute
limited partner without the consent of the Managing General Partner.
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell. The
value of the unit is determined by adding the sum of (1) current assets
less liabilities and (2) the present value of the future net revenues
attributable to proved reserves and by discounting the future net revenues
at a rate not in excess of the prime rate charged by NationsBank, N.A. of
Midland, Texas plus one percent (1%), which value shall be further reduced
by a risk factor discount of no more than one-third (1/3) to be determined
by the Managing General Partner in its sole and absolute discretion. No
limited partner units were purchased by the Managing General Partner,
during 1998. In 1997, 126 limited partner units were tendered to and
purchased by the Managing General Partner at an average base price of
$192.93 per unit. In 1996, 200 limited partner units were tendered to and
purchased by the Managing General Partner at an average base price of
$232.87 per unit.
Number of Limited Partner Interest Holders
As of December 31, 1998, there were 221 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 $179,000, with $163,600
distributed to the limited partners and $15,400 to the general partners.
For the year ended December 31, 1998, distributions of $30.20 per limited
partner unit were made, based upon 5,418 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 $363,956, with
$331,256 distributed to the limited partners and $32,700 to the general
partners. For the year ended December 31, 1997, distributions of $61.14
per limited partner unit were made, based upon 5,418 limited partner units
outstanding. During 1996, twelve monthly distributions were made totaling
$454,785, with $414,535 distributed to the limited partners and $40,250 to
the general partners. For the year ended December 31, 1996, distributions
of $76.51 per limited partner unit were made, based upon 5,418 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:
Year ended December 31,
-------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Revenues $ 54,628 377,633 531,508 342,727 160,868
Net income (loss) (588,592) (133,264) 285,720 42,213 65,169
Partners' share of net
income (loss):
General partners 3,061 23,329 40,382 29,253 10,341
Limited partners (591,653) (156,593) 245,338 12,960 54,828
Limited partners' net
income per unit (109.20) (28.90) 45.28 2.39 10.12
Limited partners' cash
distribution per unit 30.20 61.14 76.51 71.78
10.46
Total assets $ 576,182 1,343,774 1,841,0142,010,0592,406,555
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized as a
Delaware limited partnership on May 5, 1992. The offering of limited
partnership interests began August 20, 1992, 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 10, 1992, and the Offering Period terminated April 30, 1993 with
213 limited partners purchasing 5,418 units for $2,709,000.
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 farm-out arrangements and on the depletion of wells. Since
wells deplete over time, production can generally be expected to decline
from year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the limited
partners has fluctuated over the past few years and is expected to
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 12% 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 $ 11.33 18.80 (40%)
Average price per mcf of gas $ 1.69 2.25 (25%)
Oil production in barrels 12,000 16,100 (25%)
Gas production in mcf 125,100 161,900 (23%)
Income from net profits interests $ 83,345 279,147 (70%)
Partnership distributions $ 179,000 363,956 (51%)
Limited partner distributions $ 163,600 331,256 (51%)
Per unit distribution to limited partners $ 30.20 61.14 (51%)
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $83,345
from $279,147 for the years ended December 31, 1998 and 1997, respectively,
a decrease of 70%. 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 $7.47 per barrel, resulting in
a decrease of approximately $120,300 in income from net profits
interests. Oil sales represented 39% of total oil and gas sales during
the year ended December 31, 1998 as compared to 45% 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 25%, or $.56 per mcf, resulting in
a decrease of approximately $90,700 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
$211,000. 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 4,100 barrels or 25% during the
year ended December 31, 1998 as compared to the year ended December 31,
1997, resulting in a decrease of approximately $46,500 in income from
net profits interests.
Gas production decreased approximately 36,800 mcf or 23% during the
same period, resulting in a decrease of approximately $62,200 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $108,700. The decline in oil and
gas production is due primarily to property sales and a gas plant
explosion which stopped production on some wells for March and April of
1998.
3. Lease operating costs and production taxes were 32% lower, or
approximately $123,800 less during the year ended December 31, 1998 as
compared to the year ended December 31, 1997. Lease operating costs
decreased primarily due 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 increased to $643,220 from $510,897 for the years
ended December 31, 1998 and 1997, respectively, an increase of 26%. The
increase is the result of higher general and administrative costs and
provision for impairment, partially offset by a decrease in depletion
expense.
1. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 9%
or approximately $4,200 during the year ended December 31, 1998 as
compared to the year ended December 31, 1997. The increase in general
and administrative costs are the result of higher accounting fees due
to the necessity of contracting out preparation of tax depletion and K-
1 schedules.
2. Depletion expense decreased to $187,000 for the year ended December
31, 1998 from $249,000 for the same period in 1997. This represents a
decrease of 25%. 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 $17,000 as of
December 31, 1997.
The Partnership reduced the net capitalized costs of oil and gas
properties by $402,040. This provision for impairment had the effect
of reducing net income, but did not affect cash flow or partner
distributions. See Summary of Significant Accounting Policies - Oil
and Gas Properties.
<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 $ 18.80 20.95 (10%)
Average price per mcf of gas $ 2.25 2.22 1%
Oil production in barrels 16,100 19,600 (18%)
Gas production in mcf 161,900 202,500 (20%)
Income from net profits interests $ 279,147 451,477 (38%)
Partnership distributions $ 363,956 454,785 (20%)
Limited partner distributions $ 331,256 414,535 (20%)
Per unit distribution to limited partners $ 61.14 76.51 (20%)
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $279,147
from $451,477 for the years ended December 31, 1997 and 1996, respectively,
a decrease of 38%. 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 10%, or $2.15 per barrel, resulting in
a decrease of approximately $42,100 in income from net profits
interests. Oil sales represented 45% of total oil and gas sales during
the year ended December 31, 1997 as compared to 48% 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 1%, or $.03 per mcf, resulting in
an increase of approximately $6,100 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
$36,000 . 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 3,500 barrels or 18% during the
year ended December 31, 1997 as compared to the year ended December 31,
1996, resulting in a decrease of approximately $65,800 in income from
net profits interests.
Gas production decreased approximately 40,600 mcf or 20% during the
same period, resulting in a decrease of approximately $91,400 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $157,200. The decrease in
production is due primarily to a well being shut-in for 30 days and
normal decline.
3. Lease operating costs and production taxes were 5% lower, or
approximately $21,100 less during the year ended December 31, 1997 as
compared to the year ended December 31, 1996.
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 monthly from October 1994 to January 1998.
Costs and Expenses
Total costs and expenses increased to $510,897 from $245,788 for the years
ended December 31, 1997 and 1996, respectively, an increase of 108%. The
increase is the result of higher depletion expense and a provision for
impairment of oil and gas properties.
1. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
less than one percent or approximately $100 during the year ended
December 31, 1997 as compared to the year ended December 31, 1996.
3. Depletion expense increased to $249,000 for the year ended December
31, 1997 from $186,000 for the same period in 1996. This represents an
increase of 34%. 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 $88,000 as of
December 31, 1996.
The Partnership reduced the net capitalized costs of oil and gas
properties by $202,822. This provision for impairment had the effect
of reducing net income, but did not affect cash flow or partner
distributions. See Summary of Significant Accounting Policies - Oil
and Gas Properties.
<PAGE>
C. Revenue and Distribution Comparison
Partnership net income or (loss) for the years ended December 31, 1998,
1997 and 1996 was $(588,592), $(133,264) and $285,720 respectively.
Excluding the effects of depreciation, depletion, amortization and
provision for impairment, net income for the years ended December 31, 1998,
1997 and 1996 would have been $448, $327,711 and $481,493, respectively.
Correspondingly, Partnership distributions for the years ended December 31,
1998, 1997 and 1996 were $179,000, $363,956 and 454,785, respectively.
These differences are indicative of the changes in oil and gas prices,
production and properties during 1998, 1997 and 1996.
The sources for the 1998 distributions of $179,000 were oil and gas
operations of approximately $106,900 and the change in oil and gas
properties of approximately $77,300, result in excess cash for
contingencies or subsequent distributions. The sources for the 1997
distributions of $363,956 were oil and gas operations of approximately
$366,400 and the change in oil and gas properties of approximately $43,200,
result in excess cash for contingencies or subsequent distributions. The
sources for the 1996 distributions of $454,785 were oil and gas operations
of approximately $379,900, refund of excess capital of approximately
$48,100 and property sales of approximately $6,200, with the balance from
available cash on hand at the beginning of the period.
Total distributions during the year ended December 31, 1998 were $179,000
of which $163,600 was distributed to the limited partners and $15,400 to
the general partners. The per unit distribution to limited partners during
the same period was $30.20. Total distributions during the year ended
December 31, 1997 were $363,956 of which $331,256 was distributed to the
limited partners and $32,700 to the general partners. The per unit
distribution to limited partners during the same period was $61.14. Total
distributions during the year ended December 31, 1996 were $454,785 of
which $414,535 was distributed to the limited partners and $40,250 to the
general partners. The per unit distribution to limited partners during the
same period was $76.51.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,534,448 have been made to the partners. As of December 31, 1998,
$1,403,198 or $258.99 per limited partner unit, has been distributed to the
limited partners, representing a 52% 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 $106,900 in
1998 compared to $366,400 in 1997 and approximately $379,900 in 1996. The
primary source of the 1998 cash flow from operating activities was
profitable operations.
Cash flows provided by or investing activities were approximately $77,300
in 1998 compared to $43,200 in 1997 and approximately $7,900 in 1996. The
principal source of the 1998 cash flow from investing activities was from
the sale of oil and gas properties.
Cash flows provided by financing activities were approximately $179,000 in
1998 compared to $364,000 in 1997 and approximately $454,800 in 1996. The
only 1998 use in financing activities was the distributions to partners.
As of December 31, 1998, the Partnership had approximately $88,300 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
Statement 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-A, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Royalties
Institutional Income Fund XI-A, 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-A, 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-A, 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-A, 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-A, 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-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 1998 and 1997
1998 1997
---- ----
Assets
Current assets:
Cash and cash equivalents $ 57,406 52,190
Receivable from Managing General Partner 30,869 85,473
Accounts receivable - 53,536
- --------- ---------
Total current assets
88,275 191,199
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 2,029,769 2,105,397
Less accumulated depreciation,
depletion and amortization
1,541,862 952,822
- --------- ---------
Net oil and gas properties
487,907 1,152,575
- --------- ---------
$
576,182 1,343,774
========= =========
Liabilities and Partners' Equity
Partners' equity:
General partners $ (25,178) (12,839)
Limited partners 601,360 1,356,613
- --------- ---------
Total partners' equity
576,182 1,343,774
- --------- ---------
$
576,182 1,343,774
========= =========
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, 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 $ 83,345 279,147 451,477
Interest 1,441 4,062 2,362
Miscellaneous income (30,159) 94,424 77,669
-------
- ------- ------
54,628
377,633 531,508
-------
- ------- ------
Expenses
General and administrative 54,180 49,922 50,015
Depreciation, depletion and amortization 187,000 258,153 195,773
Provision for impairment of oil and gas
properties 402,040 202,822 -
-------
- ------- ------
643,220
510,897 245,788
-------
- ------- ------
Net income (loss) $ (588,592) (133,264) 285,720
=======
======= ======
Net income (loss) allocated to:
Managing General Partner $ 2,755 20,996 36,344
=======
======= ======
General partner $ 306 2,333 4,038
=======
======= ======
Limited partners $ (591,653) (156,593) 245,338
=======
======= ======
Per limited partner unit $ (109.20) (28.90) 45.28
=======
======= ======
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
Years ended December 31, 1998, 1997, 1996
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, 1995 $ (3,600) 2,013,6592,010,059
Net income 40,382 245,338 285,720
Distributions (40,250) (414,535)(454,785)
-------
- --------- ---------
Balance at December 31, 1996 (3,468) 1,844,4621,840,994
Net income (loss) 23,329 (156,593)(133,264)
Distributions (32,700) (331,256)(363,956)
-------
- --------- ---------
Balance at December 31, 1997 (12,839) 1,356,6131,343,774
Net income (loss) 3,061 (591,653)(588,592)
Distributions (15,400) (163,600)(179,000)
-------
- --------- ---------
Balance at December 31, 1998 $ (25,178) 601,360 576,182
======
========== =========
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, 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 $ 139,461 412,279 427,599
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(33,964) (49,922)(50,015)
Interest received 1,441 4,062 2,362
---------
- --------- ---------
Net cash provided by operating activities 106,938 366,419
379,946
---------
- --------- ---------
Cash flows from investing activities:
Organization costs - - 1,682
Additions to oil and gas properties - - -
Sale of oil and gas properties 77,278 43,152 6,199
---------
- --------- ---------
Net cash provided by investing
activities 77,278 43,152
7,881
---------
- --------- ---------
Cash flows from financing activities:
Distributions to partners (179,000) (363,976)(454,765)
---------
- --------- ---------
Net increase (decrease) in cash and cash
equivalents 5,216 45,595
(66,938)
Beginning of period 52,190 6,595 73,533
---------
- --------- ---------
End of period $ 57,406 52,190 6,595
=========
========= =========
(continued)
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, 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) $ (588,592) (133,264) 285,720
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 187,000 258,153
195,773
Provision for impairment of oil and gas
properties 402,040 202,822
- -
Decrease (increase) in receivables 56,116 38,708(101,547)
Increase in payables 50,374 - -
-------
- ------- -------
Net cash provided by operating activities $ 106,938 366,419 379,946
=======
======= =======
Supplemental schedule of noncash investing
and financing activities:
Oil and gas properties included in receivable
from Managing General Partner $
- - 1,650 -
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized
under the laws of the state of Delaware on May 5, 1992, 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
Partners 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%
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 costs 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 a 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-A, 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. As of December 31, 1998, the net
capitalized cost exceeded the estimated present value of oil and gas
reserves, thus an adjustment of $402,040 was made to the financial
statement. As of December 31, 1997, the net capitalized cost exceeded
the estimated present value of oil and gas reserves, thus an
adjustment of $202,822 was made to the financial statement. As
December 31, 1996 the net capitalized costs did not exceed the
estimated present value of oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net
profits interests in proved properties located within the continental
United States. A net profits interest is created when the owner of a
working interest in a property enters into an arrangement providing
that the net profits interest owner will receive a stated percentage
of the net profit from the property. The net profits interest owner
will not otherwise participate in additional costs and expenses of the
property.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, 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.
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 there were no
significant amounts of imbalance in terms of units and value. As of
December 31, 1997 and 1996 the Partnership was over produced by 3,521
and 2,974 mcf.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," the
Partnership's tax basis in its net oil and gas properties at December
31, 1998 and 1997 is $517,965 and $136,512 more, respectively, as that
shown on the accompanying Balance Sheets in accordance with generally
accepted accounting principles.
Cash and Cash Equivalents
For purposes of the statements of cash flows, the Partnership
considers all highly liquid debt instruments purchased with a maturity
of three months or less to be cash equivalents. The Partnership
maintains its cash at one financial institution.
Number of Limited Partner Units
As of December 31, 1998, 1997 and 1996 there were 5,418 limited
partner units outstanding held by 221 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.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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.
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.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Commitments and Contingent Liabilities - continued
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.
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 $60,100, $70,000 and $73,000 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
$10, $500 and $2,400 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
$37,442 during 1998 and $42,000 during 1997 and 1996, as an
administrative fee for indirect general and administrative overhead
expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $30,869 and $85,473 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 1998 and 1997.
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 service provided to the
Partnership for the year ended December 31, 1998, and approximating
$30 and $120 for the years ended December 31, 1997 and 1996,
respectively.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchasers, where the loss of one
would have a material adverse impact on the Partnership. Four
purchasers accounted for 63% of the Partnership's total oil and gas
production during 1998: American Processing for 22%, Nustar Joint
Venture for 14%, Navajo Refining Company, Inc. for 14% and
Southwestern Energy Prod. Company for 13%. Two purchasers accounted
for 37% of the Partnership's total oil and gas production during 1997:
American Processing for 24%, and Navajo Refining Company, Inc. for
13%. Three purchasers accounted for 47% of the Partnership's total oil
and gas production during 1996: American Processing 20%, Navajo
Refining Company, Inc. 14% and Torch Operating Company 13%. 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.
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 163,000 1,946,000
Revision of estimates in place 23,000 194,000
Production (20,000) (202,000)
Sale of minerals in place - (72,000)
------- ---------
December 31, 1996 166,000 1,866,000
Revision of estimates in place (56,000) (695,000)
Production (16,000) (162,000)
Sale of minerals in place (2,000) (1,000)
------- ---------
December 31, 1997 92,000 1,008,000
Revision of estimates in place (33,000) (16,000)
Production (12,000) (125,000)
Sale of minerals in place (20,000) (104,000)
------- ---------
December 31, 1998 27,000 763,000
======= =========
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
Proved developed reserves -
Oil (bbls) Gas
(mcf)
---------- --------
- -
December 31, 1996 165,000 1,821,000
======= =========
December 31, 1997 91,000 965,000
======= =========
December 31, 1998 27,000 753,000
======= =========
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
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
$9.22 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 $1.48 per Mcf in the
preparation of the reserve report as of January 1, 1999.
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.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing, proved developed non-producing and proved undeveloped. All
of the proved reserves are included in the engineering reports which
evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to
farm-out arrangements with the Managing General Partner or unrelated
third parties. Generally, the Partnership retains a carried interest
such as an overriding royalty interest under the terms of a farm-out,
or receives cash.
<PAGE>
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 1998, 1997 and 1996 is
presented below:
1998 1997 1996
---- ---- ----
Future cash inflows, net of
production and development
costs $ 733,000 1,709,000 5,948,000
10% annual discount for
estimated timing of cash
flows 245,000 556,000 2,454,000
--------- --------- ---------
Standardized measure of
discounted future net cash
flows $ 488,000 1,153,000 3,494,000
========= ========= =========
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 $ (83,000) (279,000) (841,000)
Changes in prices and production costs (349,000)(1,912,000)
1,999,000
Changes of production rates
(timing) and others (110,000) 262,000 146,000
Revisions of previous
quantities estimates (118,000) (758,000) (315,000)
Accretion of discount 115,000 349,000 337,000
Sales of minerals in place (120,000) (3,000) (36,000)
Discounted future net
cash flows -
Beginning of year 1,153,000 3,494,000 2,204,000
--------- --------- ---------
End of year $ 488,000 1,153,000 3,494,000
========= ========= =========
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.
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.
<PAGE>
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.
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.
<PAGE>
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 $37,442 during 1998 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. Through prior purchases, the Managing
General Partner also owns 326 limited partner units, or 6.0% limited
partner interest. The Managing General Partner total percentage interest
ownership in the Partnership is 14.4%.
No officer or director of the Managing General Partner owns Units in the
Partnership. H. H. Wommack, III, as the individual general partner of the
Partnership, owns a one percent interest as a general partner. The
officers and directors of the Managing General Partner are considered
beneficial owners of the limited partner units acquired by the Managing
General Partner by virtue of their status as such. A list of beneficial
owners of limited partner units, acquired by the Managing General Partner,
is as follows:
<PAGE>
Amount and
Nature of Percent
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------------- --------------- -------
Limited Partnership Southwest Royalties, Inc. Directly Owns 14.4%
Interest Managing General Partner
326 Units
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns 14.4%
Interest Chairman of the Board,
326 Units
President, CEO, Treasurer
and Director of Southwest
Royalties, Inc., the
Managing General Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. Allen Corey Indirectly Owns 14.4%
Interest Secretary and Director of
326 Units
Southwest Royalties, Inc.,
the Managing General
Partner
633 Chestnut Street
Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns 14.4%
Interest Vice President and CFO of
326 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership Jon P. Tate Indirectly Owns 14.4%
Interest Vice President, Land and
326 Units
Assistant Secretary of
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns 14.4%
Interest Vice President, Marketing
326 Units
of Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
<PAGE>
Amount and
Nature of
Percent
Name and Address ofBeneficial
of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------------- --------------- -------
Limited Partnership R. Douglas Keathley Indirectly Owns 14.4%
Interest Vice President,326 Units
Operations of Southwest
Royalties, Inc., the
Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns 14.4%
Interest Director of Southwest
326 Units
Royalties, Inc., the
Managing General Partner
407 N. Big Spring Street
Midland, TX 79701
There are no arrangements known to the Managing General Partner which may
at a subsequent date result in a change of control of the Partnership.
<PAGE>
Item 13. Certain Relationships and Related Transactions
In 1998, the Managing General Partners received $37,442 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 $60,100 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 $10 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-A, L.P., dated May 5, 1992. (Incorporated by
reference from the Partnership's Form 10-K for
the fiscal year ended December 31, 1992.)
(b) Agreement of Limited Partnership
of Southwest Royalties Institutional Income Fund
XI-A, L.P., dated May 5, 1992. (Incorporated by
reference from the Partnership's Form 10-K for
the fiscal year ended December 31, 1992.)
27 Financial Data Schedule
(b) Report on Form 8-K
The Partnership filed an 8-K on October 28, 1998 under
Item 2 "Acquisition or Disposition of Asset." On
December 15, 1998 an 8-K/A was filed concerning proforma
information the disposition.
<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-A, L.P., a Delaware limited partnership
By: Southwest Royalties, Inc., Managing
General
Partner
By: /s/ H. H. Wommack, III
-----------------------------
H. H. Wommack, III,
President
Date: March 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> 57,406
<SECURITIES> 0
<RECEIVABLES> 30,869
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 88,275
<PP&E> 2,029,769
<DEPRECIATION> 1,541,862
<TOTAL-ASSETS> 576,182
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 576,182
<TOTAL-LIABILITY-AND-EQUITY> 576,182
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<TOTAL-REVENUES> 54,628
<CGS> 0
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<INCOME-PRETAX> (588,592)
<INCOME-TAX> 0
<INCOME-CONTINUING> (588,592)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (588,592)
<EPS-PRIMARY> (109.20)
<EPS-DILUTED> (109.20)
</TABLE>
