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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 June 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 17.
<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 notes 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
six month periods ended June 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
June 30, December 31,
1999 1998
--------- ------------
(unaudited)
Assets
Current assets:
Cash and cash equivalents $ 11,967 2,410
Receivable from Managing General Partner 17,442 4,796
Distribution receivable 70 -
--------- ---------
Total current assets 29,479 7,206
--------- ---------
Oil and gas properties - using the
full cost method of accounting 2,007,077 2,007,920
Less accumulated depreciation,
depletion and amortization 1,647,721 1,626,721
--------- ---------
Net oil and gas properties 359,356 381,199
--------- ---------
Organization costs, net of amortization - 102
--------- ---------
$ 388,835 388,507
========= =========
Liabilities and Partners' Equity
Current liabilities:
Distribution payable $ - 79
--------- ---------
Partner equity:
General partners 3,119 797
Limited partners 385,716 387,631
--------- ---------
Total partners' equity 388,835 388,428
--------- ---------
$ 388,835 388,507
========= =========
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Statements of Operations
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
Revenues
Income (loss) from net profits
interests $ 33,792 (17,019) 48,533 16,045
Interest income from
operations 145 266 159 428
Miscellaneous income 21,000 - 21,000 -
------- ------- ------- -------
54,937 (16,753) 69,692 16,473
------- ------- ------- -------
Expenses
General and administrative 10,770 12,787 22,484 30,818
Depreciation, depletion and
amortization 8,000 20,360 21,102 47,220
Provision for impairment oil
and gas properties - 57,913 - 57,913
Miscellaneous expense - 52,707 - 55,095
------- ------- ------- -------
18,770 143,767 43,586 191,046
------- ------- ------- -------
Net income (loss) $ 36,167 (160,520) 26,106 (174,573)
======= ======= ======= =======
Net income (loss) allocated to:
Managing General Partner $ 3,975 (7,402) 4,249 (6,250)
======= ======= ======= =======
General Partner $ 442 (823) 473 (694)
======= ======= ======= =======
Limited partners $ 31,750 (152,295) 21,384 (167,629)
======= ======= ======= =======
Per limited partner unit $ 6.55 (31.39) 4.41 (34.56)
======= ======= ======= =======
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Statements of Cash Flows
(unaudited)
Six Months Ended
June 30,
1999 1998
Cash flows from operating activities:
Cash received from oil and gas sales $ 61,018 59,045
Cash paid to suppliers (26,615) (3,997)
Interest received 159 428
------- --------
Net cash provided by operating activities 34,562 55,476
------- --------
Cash flows from investing activities:
Cash proceeds from sale of oil and gas properties 1,571 520
Additions to oil and gas properties (728) -
------- --------
Net cash provided by investing activities 843 520
------- --------
Cash flows used in financing activities:
Distributions to partners (25,848) (57,463)
------- --------
Net increase (decrease) in cash and cash equivalents 9,557 (1,467)
Beginning of period 2,410 4,948
------- --------
End of period $ 11,967 3,481
======= ========
(continued)
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
Statements of Cash Flows, continued
(unaudited)
Six Months Ended
June 30,
1999 1998
Reconciliation of net income (loss) to net
cash provided by operating activities:
Net income (loss) $ 26,106 (174,573)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 21,102 47,220
Provision for impairment for oil and gas
properties - 57,913
Decrease in receivables 12,486 43,000
(Decrease) Increase in payables (25,132) 81,916
------- -------
Net cash provided by operating activities $ 34,562 55,476
======= =======
<PAGE>
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized
under the laws of the state of Delaware on August 31, 1993, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership will sell its oil
and gas production to a variety of purchasers with the prices it
receives being dependent upon the oil and gas economy. Southwest
Royalties, Inc. serves as the Managing General Partner and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partner Partners (1)
------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital
contributions 100% -
Oil and gas revenues 90% 10%
All other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to the Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
2. Summary of Significant Accounting Policies
The interim financial information as of June 30, 1999, and for the
three and six months ended June 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 year. 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. The Partnership's capitalized costs did not exceed the
estimated present value of reserves as of June 30, 1999. The oil price
environment experienced during 1998 had an adverse affect on the Company's
revenues and operating cash flow. Further declines of oil prices during
1999 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 June 30, 1999 and 1998
The following table provides certain information regarding performance
factors for the quarters ended June 30, 1999 and 1998:
Three Months
Ended Percentage
June 30, Increase
1999 1998 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 15.89 12.29 29%
Average price per mcf of gas $ 1.99 1.59 25%
Oil production in barrels 2,000 2,500 (20%)
Gas production in mcf 20,800 21,500 (3%)
Income from net profits interests $ 33,792 (17,019) 299%
Partnership distributions $ 25,699 24,000 7%
Limited partner distributions $ 23,299 21,600 8%
Per unit distribution to limited
partners $ 4.80 4.45 8%
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests increased to $33,792
from $(17,019) for the quarters ended June 30, 1999 and 1998, respectively,
an increase of 299%. The principal factors affecting the comparison of the
quarters ended June 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 June 30, 1999 as compared to the
quarter ended June 30, 1998 by 29%, or $3.60 per barrel, resulting in
an increase of approximately $9,000 in income from net profits
interests. Oil sales represented 43% of total oil and gas sales during
the quarter ended June 30, 1999 as compared to 47% during the quarter
ended June 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 25%, or $.40 per mcf, resulting in
an increase of approximately $8,600 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
$17,600. 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 500 barrels or 20% during the
quarter ended June 30, 1999 as compared to the quarter ended June 30,
1998, resulting in a decrease of approximately $7,900 in income from
net profits interests.
Gas production decreased approximately 700 mcf or 3% during the same
period, resulting in a decrease of approximately $1,400 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $9,300. The decrease of oil
production is primarily due to downtime on one well and natural
decline.
3. Lease operating costs and production taxes were 36% lower, or
approximately $22,000 less during the quarter ended June 30, 1999 as
compared to the quarter ended June 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 necessary to increase
production and perform major repairs thus making it necessary to shut-
in some wells.
Costs and Expenses
Total costs and expenses decreased to $18,770 from $143,767 for the
quarters ended June 30, 1999 and 1998, respectively, a decrease of 86%.
The decrease is the result of lower depletion expense, general and
administrative expense, and miscellaneous 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
16% or approximately $2,000 during the quarter ended June 30, 1999 as
compared to the quarter ended June 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 $8,000 for the quarter ended June 30,
1999 from $18,500 for the same period in 1998. This represents a decrease
of 57%. 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 April
1, 1999 as compared to 1998 and the decrease in gross oil and gas revenues.
3. The Partnership entered into a purchase agreement on the Kaiser State
lease that guaranteed net income each month for a specified period of
time. This income was recorded on the Partnerships books as
miscellaneous income. This property was sold effective May 1998.
4. 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 $52,707 was found to be necessary. This adjustment was
recorded as miscellaneous expense on the Partnerships books for the
quarter ended June 30, 1998.
<PAGE>
B. General Comparison of the Six Month Periods Ended June 30, 1999 and
1998
The following table provides certain information regarding performance
factors for the six month periods ended June 30, 1999 and 1998:
Six Months
Ended Percentage
June 30, Increase
1999 1998 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 12.87 12.22 5%
Average price per mcf of gas $ 1.79 1.59 13%
Oil production in barrels 4,300 5,300 (19%)
Gas production in mcf 39,100 41,600 (6%)
Income from net profits interests $ 48,533 16,045 202%
Partnership distributions $ 25,699 57,500 (55%)
Limited partner distributions $ 23,299 51,750 (55%)
Per unit distribution to limited
partners $ 4.80 10.67 (55%)
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests increased to $48,533
from $16,045 for the six months ended June 30, 1999 and 1998, respectively,
an increase of 202%. The principal factors affecting the comparison of the
six months ended June 30, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the six months ended June 30, 1999 as compared to the
six months ended June 30, 1998 by 5%, or $.65 per barrel, resulting in
an increase of approximately $3,400 in income from net profits
interests. Oil sales represented 44% of total oil and gas sales during
the six months ended June 30, 1999 as compared to 49% during the six
months ended June 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 13%, or $.20 per mcf, resulting in
an increase of approximately $8,300 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
$11,700. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
<PAGE>
2. Oil production decreased approximately 1,000 barrels or 19% during the
six months ended June 30, 1999 as compared to the six months ended June
30, 1998, resulting in a decrease of approximately $12,900 in income
from net profits interests.
Gas production decreased approximately 2,500 mcf or 6% during the same
period, resulting in a decrease of approximately $4,500 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $17,400. The decrease of oil
production is primarily due to downtime on one well and natural
decline.
3. Lease operating costs and production taxes were 33% lower, or
approximately $38,000 less during the six months ended June 30, 1999 as
compared to the six months ended June 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 necessary to increase
production and perform major repairs thus making it necessary to shut-
in some wells.
Costs and Expenses
Total costs and expenses decreased to $43,586 from $191,046 for the six
months ended June 30, 1999 and 1998, respectively, a decrease of 77%. The
decrease is the result of lower general and administrative expense and
miscellaneous 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 approximately $8,300 during the six months ended June 30, 1999
as compared to the six months ended June 30, 1998.
2. Depletion expense decreased to $21,000 for the six months ended June
30, 1999 from $43,500 for the same period in 1998. This represents a
decrease of 52%. Depletion is calculated using the units of revenue method
of amortization based on a percentage of current period gross revenues to
total future gross oil and gas revenues, as estimated by the Partnership's
independent petroleum consultants. 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 April
1, 1999 as compared to 1998 and the decrease in gross oil and gas revenues.
3. The Partnership entered into a purchase agreement on the Kaiser State
lease that guaranteed net income each month for a specified period of
time. This income was recorded on the Partnerships books as
miscellaneous income. This property was sold effective May 1998.
4. 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 $52,707 was found to be necessary. This adjustment was
recorded as miscellaneous expense on the Partnerships books for the
quarter ended June 30, 1998.
<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 $34,600 in
the six months ended June 30, 1999 as compared to approximately $55,500 in
the six months ended June 30, 1998. The primary source of the 1999 cash
flow from operating activities was profitable operations.
Cash flows provided by investing activities were approximately $800 in the
six months ended June 30, 1999 as compared to approximately $500 in the six
months ended June 30, 1998.
Cash flows used in financing activities were approximately $25,800 in the
six months ended June 30, 1999 as compared to approximately $57,500 in the
six months ended June 30, 1998. The only use in financing activities was
the distributions to partners.
Total distributions during the six months ended June 30, 1999 were $25,699
of which $23,299 was distributed to the limited partners and $2,400 to the
general partners. The per unit distribution to limited partners during the
six months ended June 30, 1999 was $4.80. Total distributions during the
six months ended June 30, 1998 were $57,500 of which $51,750 was
distributed to the limited partners and $5,750 to the general partners.
The per unit distribution to limited partners during the six months ended
June 30, 1998 was $10.67.
The source for the 1999 distributions of $25,699 was oil and gas operations
of approximately $34,600 and the net change in oil and gas properties of
approximately $800, resulting in excess cash for contingencies or
subsequent distributions. The source for the 1998 distributions of $57,500
was oil and gas operations of approximately $55,500.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,015,138 have been made to the partners. As of June 30, 1999,
$927,652 or $191.23 per limited partner unit has been distributed to the
limited partners, representing a 38% return of the capital contributed.
As of June 30, 1999, the Partnership had approximately $29,500 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 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.
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.
<PAGE>
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.
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>
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) Reports on Form 8-K:
No reports on Form 8-
K were filed during the quarter ended June 30, 1999.
<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: August 15, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Balance Sheet at June 30, 1999 (Unaudited) and the Statement of Operations
for the Six Months Ended June 30, 1999 (Unaudited) and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 11,967
<SECURITIES> 0
<RECEIVABLES> 17,512
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 29,479
<PP&E> 2,007,077
<DEPRECIATION> 1,647,721
<TOTAL-ASSETS> 388,835
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 388,835
<TOTAL-LIABILITY-AND-EQUITY> 388,835
<SALES> 48,533
<TOTAL-REVENUES> 69,692
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 43,586
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 26,106
<INCOME-TAX> 0
<INCOME-CONTINUING> 26,106
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 26,106
<EPS-BASIC> 4.41
<EPS-DILUTED> 4.41
</TABLE>
