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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________________ to _______________
Commission file number 33-47668-02
SOUTHWEST ROYALTIES INSTITUTIONAL 1992-93 INCOME PROGRAM
Southwest Royalties Institutional Income Fund XI-B, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2427289
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
_________Midland, Texas 79701_________
(Address of principal executive offices)
________(915) 686-9927________
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all 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 _____
The total number of pages contained in this report is 18.
<PAGE>
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the note thereto for
the year ended December 31, 1998 which are found in the Registrant's Form
10-K Report for 1998 filed with the Securities and Exchange Commission.
The December 31, 1998 balance sheet included herein has been taken from the
Registrant's 1998 Form 10-K Report. Operating results for the three and
nine month periods ended September 30, 1999 are not necessarily indicative
of the results that may be expected for the full year.
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Balance Sheets
September 30, December 31,
1999 1998
------------- ------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ 33,098 2,410
Receivable from Managing General Partner 31,570 4,796
Distribution receivable 70 -
--------- ---------
Total current assets 64,738 7,206
--------- ---------
Oil and gas properties - using the
full cost method of accounting 2,007,061 2,007,920
Less accumulated depreciation,
depletion and amortization 1,654,721 1,626,721
--------- ---------
Net oil and gas properties 352,340 381,199
--------- ---------
Organization costs, net - 102
--------- ---------
$ 417,078 388,507
========= =========
Liabilities and Partners' Equity
Current liability
Distribution payable $ - 79
--------- ---------
Partners' equity
General partners 6,643 797
Limited partners 410,435 387,631
--------- ---------
Total partners' equity 417,078 388,428
--------- ---------
$ 417,078 388,507
========= =========
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Statements of Operations
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
Revenues
Income from net profits
interests $ 71,505 18,319 120,037 34,365
Interest income from operations 355 15 514
443
Miscellaneous income - 9,937 21,000 (45,159)
------ ------- ------- -------
71,860 28,271 141,551 (10,351)
------ ------- ------- -------
Expenses
General and administrative 9,617 13,192 32,100 44,010
Depreciation, depletion and
amortization 7,000 17,860 28,102 65,080
Provision for impairment of
oil and gas properties - - - 57,913
------ ------- ------- -------
16,617 31,052 60,202 167,003
------ ------- ------- -------
Net income (loss) $ 55,243 (2,781) 81,349 (177,354)
====== ======= ======= =======
Net income (loss) allocated to:
Managing General Partner $ 5,602 1,357 9,851 (4,892)
====== ======= ======= =======
General Partner $ 622 151 1,094 (544)
====== ======= ======= =======
Limited Partners $ 49,019 (4,289) 70,404 (171,918)
====== ======= ======= =======
Per limited partner unit $ 10.10 (.88) 14.51 (35.44)
====== ======= ======= =======
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
1999 1998
---- ----
Cash flows from operating activities
Cash received from oil and gas sales $ 113,495 73,885
Cash paid to suppliers (31,332) (18,916)
Interest received 514 443
------- -------
Net cash provided by operating activities 82,677 55,412
------- -------
Cash flows provided by investing activities
Cash received from sale of oil and gas
property interest 1,571 1,937
Additions to oil and gas properties (712) (1,409)
------- -------
Net cash provided by investing activities 859 528
------- -------
Cash flows used in financing activities
Distributions to partners (52,848) (58,423)
------- -------
Net increase (decrease) in cash and cash equivalents 30,688
(2,483)
Beginning of period 2,410 4,948
------- -------
End of period $ 33,098 2,465
======= =======
(continued)
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Statements of Cash Flows, continued
(unaudited)
Nine Months Ended
September 30,
1999 1998
---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities
Net income (loss) $ 81,349 (177,354)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depreciation, depletion and amortization 28,102 65,080
Provision for impairment of oil and gas properties -
57,913
(Increase) decrease in receivables (6,542) 39,520
(Decrease) increase in payables (20,232) 70,253
------- -------
Net cash provided by operating activities $ 82,677 55,412
======= =======
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized
under the laws of the state of Delaware on August 31, 1993, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership will sell its oil
and gas production to a variety of purchasers with the prices it
receives being dependent upon the oil and gas economy. Southwest
Royalties, Inc. serves as the Managing General Partner and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partner Partners (1)
------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital contributions100% -
Oil and gas revenues 90% 10%
All other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to the Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
2. Summary of Significant Accounting Policies
The interim financial information as of September 30, 1999, and for
the three and nine months ended September 30, 1999, is unaudited.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim
financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments
are of a normal recurring nature. The interim consolidated financial
statements should be read in conjunction with the audited financial
statements for the year ended December 31, 1998.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized as a
Delaware limited partnership on August 31, 1993. The offering of such
limited partnership interests began October 25, 1993, as part of a shelf
offering registered under the name Southwest Royalties Institutional 1992-
93 Income Program. Minimum capital requirements for the Partnership were
met on December 8, 1993, with the offering of limited partnership interests
concluding August 20, 1994, with total limited partner contributions of
$2,425,500.
The Partnership was formed to acquire royalty and net profits 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, sales of properties, and 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 partners is
therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management does not anticipate performing
workovers during the last quarter of 1999. The Partnership could possibly
experience a normal decline.
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.
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. For the quarter ended September 30, 1999, the net
capitalized cost did not exceed the estimated present value of oil and gas
reserves. A return of the oil price environment experienced during the
first two quarters of 1999 would have an adverse affect on the Company's
revenues and operating cash flow. Also, further declines in oil prices
could result in additional decreases in the carrying value of the Company's
oil and gas properties.
<PAGE>
Results of Operations
A. General Comparison of the Quarters Ended September 30, 1999 and 1998
The following table provides certain information regarding performance
factors for the quarters ended September 30, 1999 and 1998:
Three Months
Ended Percentage
September 30, Increase
1999 1998 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 21.50 11.59 86%
Average price per mcf of gas $ 2.41 1.91 26%
Oil production in barrels 2,900 2,400 21%
Gas production in mcf 21,510 24,000 (10%)
Income from net profits interests $ 71,505 18,319 290%
Partnership distributions $ 27,000 1,000 2,600%
Limited partner distributions $ 24,300 900 2,600%
Per unit distribution to limited partners $ 5.01 .19 2,600%
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests increased to $71,505
from $18,319 for the quarters ended September 30, 1999 and 1998,
respectively, an increase of 290%. The principal factors affecting the
comparison of the quarters ended September 30, 1999 and 1998 are as
follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended September 30, 1999 as compared to
the quarter ended September 30, 1998 by 86%, or $9.91 per barrel,
resulting in an increase of approximately $23,800 in income from net
profits interests. Oil sales represented 55% of total oil and gas
sales during the quarter ended September 30, 1999 as compared to 38%
during the quarter ended September 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 26%, or $.50 per mcf, resulting in
an increase of approximately $12,000 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$35,800. 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 increased approximately 500 barrels or 21% during the
quarter ended September 30, 1999 as compared to the quarter ended
September 30, 1998, resulting in an increase of approximately $10,750
in income from net profits interests.
Gas production decreased approximately 2,490 mcf or 10% during the same
period, resulting in a decrease of approximately $6,000 in income from
net profits interests.
The net total increase in income from net profits interests due to the
change in production is approximately $4,750. The increase in oil
production is in relation to a settlement of royalty on the Dagger Draw
Lease. Production interest of approximately 1,100 barrels were held in
suspense from 1993 through 1999. These dollars were received and
recorded in the Partnership during the third quarter of 1999.
3. Lease operating costs and production taxes were 27% lower, or
approximately $15,500 less during the quarter ended September 30, 1999
as compared to the quarter ended September 30, 1998. The decline in
lease operating costs is primarily in relation to the drop in oil
prices experienced throughout 1998 and into the first six months of
1999, which made it uneconomical to perform workovers and major
repairs. Although prices have increased during the third quarter of
1999, only routine repairs and maintenance for the most part are being
performed.
Costs and Expenses
Total costs and expenses decreased to $16,617 from $31,052 for the quarters
ended September 30, 1999 and 1998, respectively, a decrease of 46%. The
decrease is the result of lower depletion expense and general and
administrative expense.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
27% or $3,600 during the quarter ended September 30, 1999 as compared
to the quarter ended September 30, 1998. The decrease of general and
administrative costs were in part due to additional accounting costs
incurred in 1998 in relation to the outsourcing of K-1 tax package
preparation; a change in auditors requiring opinions from both the
predecessors and successor auditors and a new accounting pronouncement
requiring review by the independent auditors of the 10-Q's. The
Managing General Partner has also made an effort to cut back on general
and administrative costs whenever and wherever possible.
2. Depletion expense decreased to $7,000 for the quarter ended September
30, 1999 from $16,000 for the same period in 1998. This represents a
decrease of 56%. 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. Contributing
factors to the decline in depletion expense between the comparative
periods were the increase in the price of oil and gas used to determine
the Partnership's reserves for October 1, 1999 as compared to 1998.
<PAGE>
B. General Comparison of the Nine Month Periods Ended September 30, 1999
and 1998
The following table provides certain information regarding performance
factors for the nine month periods ended September 30, 1999 and 1998:
Nine Months
Ended Percentage
September 30, Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 15.51 12.02 29%
Average price per mcf of gas $ 2.01 1.71 18%
Oil production in barrels 7,590 7,700 (1%)
Gas production in mcf 60,610 65,600 (8%)
Income from net profits interests $ 120,037 34,365 249%
Partnership distributions $ 52,699 58,500 (10%)
Limited partner distributions $ 47,599 52,650 (10%)
Per unit distribution to limited partners $ 9.81 10.85 (10%)
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests increased to $120,037
from $34,365 for the nine months ended September 30, 1999 and 1998,
respectively, an increase of 249%. The principal factors affecting the
comparison of the nine months ended September 30, 1999 and 1998 are as
follows:
1. The average price for a barrel of oil received by the Partnership
increased during the nine months ended September 30, 1999 as compared
to the nine months ended September 30, 1998 by 29%, or $3.49 per
barrel, resulting in an increase of approximately $26,900 in income
from net profits interests. Oil sales represented 49% of total oil and
gas sales during the nine months ended September 30, 1999 as compared
to 45% during the nine months ended September 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 18%, or $.30 per mcf, resulting in
an increase of approximately $19,700 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$46,600. 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 110 barrels or 1% during the
nine months ended September 30, 1999 as compared to the nine months
ended September 30, 1998, resulting in a decrease of approximately
$1,700 in income from net profits interests.
Gas production decreased approximately 4,990 mcf or 8% during the same
period, resulting in a decrease of approximately $10,000 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $11,700.
3. Lease operating costs and production taxes were 31% lower, or
approximately $53,500 less during the nine months ended September 30,
1999 as compared to the nine months ended September 30, 1998. The
decline in lease operating costs is primarily in relation to the drop
in oil prices experienced throughout 1998 and into the first six months
of 1999, which made it uneconomical to perform workovers and major
repairs. Although prices have increased during the third quarter of
1999, only routine repairs and maintenance for the most part are being
performed.
Costs and Expenses
Total costs and expenses decreased to $60,202 from $167,003 for the nine
months ended September 30, 1999 and 1998, respectively, a decrease of 64%.
The decrease is the result of lower general and administrative expense and
depletion expense.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
27% or $11,900 during the nine months ended September 30, 1999 as
compared to the nine months ended September 30, 1998. The decrease of
general and administrative costs were in part due to additional
accounting costs incurred in 1998 in relation to the outsourcing of K-1
tax package preparation; a change in auditors requiring opinions from
both the predecessors and successor auditors and a new accounting
pronouncement requiring review by the independent auditors of the 10-
Q's. The Managing General Partner has also made an effort to cut back
on general and administrative costs whenever and wherever possible.
2. Depletion expense decreased to $28,000 for the nine months ended
September 30, 1999 from $59,500 for the same period in 1998. This
represents a decrease of 53%. 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.
Contributing factors to the decline in depletion expense between the
comparative periods were the increase in the price of oil and gas used
to determine the Partnership's reserves for October 1, 1999 as compared
to 1998.
3. The net capitalized costs for the nine months ended September 30, 1998
exceeded the estimated present value of oil and gas reserves,
discounted at 10% in the amount of $57,913, such excess costs were
charged to current expense. The write-down had the effect of reducing
net income, but did not affect cash flow or partner distributions.
<PAGE>
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $82,700 in
the nine months ended September 30, 1999 as compared to approximately
$55,400 in the nine months ended September 30, 1998. The primary source of
the 1999 cash flow from operating activities was profitable operations.
Cash flows provided by investing activities were approximately $900 in the
nine months ended September 30, 1999 as compared to approximately $500 in
the nine months ended September 30, 1998.
Cash flows used in financing activities were approximately $52,800 in the
nine months ended September 30, 1999 as compared to approximately $58,400
in the nine months ended September 30, 1998. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 1999 were
$52,699 of which $47,599 was distributed to the limited partners and $5,100
to the general partners. The per unit distribution to limited partners
during the nine months ended September 30, 1999 was $9.81. Total
distributions during the nine months ended September 30, 1998 were $58,500
of which $52,650 was distributed to the limited partners and $5,850 to the
general partners. The per unit distribution to limited partners during the
nine months ended September 30, 1998 was $10.85.
The source for the 1999 distributions of $52,699 was oil and gas operations
of approximately $82,700 and the change in oil and gas properties of
approximately $900, resulting in excess cash for contingencies or
subsequent distribution. The sources for the 1998 distributions of $58,500
were oil and gas operations of approximately $55,400 and the change in oil
and gas properties of approximately $500, with the balance from available
cash on hand at the beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,042,138 have been made to the partners. As of September 30, 1999,
$951,952 or $196.24 per limited partner unit has been distributed to the
limited partners, representing a 39% return of the capital contributed.
As of September 30, 1999, the Partnership had approximately $64,700 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenues generated from operations
are adequate to meet the needs of the Partnership.
<PAGE>
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
over $21.0 million of interest payments due within the next twelve months
on its debt obligations. Due to the severely depressed commodity prices
experienced for the past eighteen months, 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 has identified and assessed 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 an internal plan to identify
applicable hardware and software, assess impact and effect, estimate costs,
construct and implement corrective actions, and prepare contingency plans.
Identification & Assessment
The Managing General Partner currently believes it identified the internal
and external software and hardware that had the potential for date
sensitivity problems. Four critical systems and/or functions were
identified and addressed: (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 has met compliance
requirements. Since this is an internally generated software package, the
Managing General Partner incurred approximately $25,000 in man-hours.
Modifications were made by internal staff and did 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 that were modified, it is
anticipated that some problems may arise, but having met the early
completion date, the Managing General Partner feels that adequate time
remains available to overcome unforeseen delays.
<PAGE>
DEC has released a fully compliant version of its operating system that is
used by the Partnership on the DEC VAX system. It was installed, the
Managing General Partner believes that this solved any potential problems
on the system.
The Managing General Partner has identified various third-party software
that may have date sensitivity problems and is continuing to work 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 year end 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.
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, due to the external nature of the potential
problems, 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 year-end 1999.
<PAGE>
Worst Case Scenario
The Securities and Exchange Commission requires public companies to
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>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a)Exhibits:
27 Financial Data Schedule
(b) No reports on Form 8-K were filed during the quarter for
which this report is filed.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Southwest Royalties Institutional
Income Fund XI-B, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
------------------------------
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: November 15, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Balance Sheet at September 30, 1999 (Unaudited) and the Statement of
Operations for the Nine Months Ended September 30, 1999 (Unaudited) and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 33,098
<SECURITIES> 0
<RECEIVABLES> 31,640
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 64,738
<PP&E> 2,007,061
<DEPRECIATION> 1,654,721
<TOTAL-ASSETS> 417,078
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 417,078
<TOTAL-LIABILITY-AND-EQUITY> 417,078
<SALES> 120,037
<TOTAL-REVENUES> 141,551
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 60,202
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 81,349
<INCOME-TAX> 0
<INCOME-CONTINUING> 81,349
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 81,349
<EPS-BASIC> 14.51
<EPS-DILUTED> 14.51
</TABLE>
