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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, 2002
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 33-47668-01
SOUTHWEST ROYALTIES INSTITUTIONAL 1992-93 INCOME PROGRAM
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 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 20.
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, 2001, which are found in the Registrant's Form
10-K Report for 2001 filed with the Securities and Exchange Commission.
The December 31, 2001 balance sheet included herein has been taken from the
Registrant's 2001 Form 10-K Report. Operating results for the three and
nine month periods ended September 30, 2002 are not necessarily indicative
of the results that may be expected for the full year.
Southwest Royalties Institutional Income Fund XI-A, L.P.
Balance Sheets
September December
30, 31,
2002 2001
----------- ---------
(unaudited)
Assets
- ------
Current assets:
Cash and cash equivalents $ 26,232 22,949
Receivable from Managing General 23,876 11,500
Partner
Distribution receivable 1 -
--------- ---------
Total current assets 50,109 34,449
--------- ---------
Oil and gas properties - using the
full-
cost method of accounting 2,029,769 2,029,769
Less accumulated depreciation,
depletion and amortization 1,707,862 1,688,862
--------- ---------
Net oil and gas properties 321,907 340,907
--------- ---------
$ 372,016 375,356
========= =========
Liabilities and Partners' Equity
- --------------------------------
Current liability - distribution $ - 757
payable
--------- ---------
Partners' equity:
General partners (27,599) (29,241)
Limited partners 399,615 403,840
--------- ---------
Total partners' equity 372,016 374,599
--------- ---------
$ 372,016 375,356
========= =========
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended Nine Months
Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
Revenues
- --------
Income from net profits $ 24,839 33,528 94,935 201,247
interests
Interest 81 454 187 2,036
------- ------- ------- -------
24,920 33,982 95,122 203,283
------- ------- ------- -------
Expenses
- --------
General and administrative 11,151 10,053 31,705 30,898
Depreciation, depletion and
amortization 5,000 31,000 19,000 63,000
------- ------- ------- -------
16,151 41,053 93,898
50,705
------- ------- ------- -------
Net income (loss) $ 8,769 (7,071) 109,385
44,417
======= ======= ======= =======
Net income (loss) allocated
to:
Managing General Partner $ 1,239 2,154 5,708 15,514
======= ======= ======= =======
General Partner $ 138 239 634 1,724
======= ======= ======= =======
Limited Partners $ 7,392 (9,464) 38,075 92,147
======= ======= ======= =======
Per limited partner unit $ 1.36 (1.75) 7.03 17.01
======= ======= ======= =======
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
2002 2001
---- ----
Cash flows from operating activities
Cash received from income from net
profits interests $ 88,852 270,417
Cash paid to suppliers (38,755 (28,323)
)
Interest received 187 2,036
------- -------
Net cash provided by operating activities 50,284 244,130
------- -------
Cash flows used in financing activities
Distributions to partners (47,001 (275,000)
)
------- -------
Net increase (decrease) in cash and cash 3,283 (30,870)
equivalents
Beginning of period 22,949 57,241
------- -------
End of period $ 26,232 26,371
======= =======
Reconciliation of net income to net cash
provided by operating activities
Net income $ 44,417 109,385
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation, depletion and amortization 19,000 63,000
(Increase) decrease receivables (6,083) 69,170
(Decrease) increase in payables (7,050) 2,575
------- -------
Net cash provided by operating activities $ 50,284 244,130
======= =======
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 contributions100% -
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 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 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.
2. Summary of Significant Accounting Policies
The interim financial information as of September 30, 2002, and for
the three and nine months ended September 30, 2002, 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, 2001.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-A, L.P. (the Partnership)
was organized as a Delaware limited partnership on May 5, 1992. The
offering of such 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 concluding on
April 30, 1993 with total limited partner contributions of $2,709,000.
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 the net
proceeds from operations to the limited and general partners. Net revenues
from producing oil and gas properties will not be reinvested in other
revenue producing assets except to the extent that production facilities
and wells are improved or reworked or where methods are employed to improve
or enable more efficient recovery of oil and gas reserves.
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 anticipates performing no workovers
during 2002 to enhance production. The partnership will most likely
experience the historical production decline of approximately 9% per year.
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, 2002, the net
capitalized costs did not exceed the estimated present value.
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.
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.
The Partnership recognizes income from its net profits interest in oil and
gas property on an accrual basis, while the quarterly cash distributions of
the net profits interest are based on a calculation of actual cash received
from oil and gas sales, net of expenses incurred during that quarterly
period. The net profits interest is a calculated revenue interest that
burdens the underlying working interest in the property, and the net
profits interest owner is not responsible for the actual development or
production expenses incurred. Accordingly, if the net profits interest
calculation results in expenses incurred exceeding the oil and gas income
received during a quarter, no cash distribution is due to the Partnership's
net profits interest until the deficit is recovered from future net
profits. The Partnership accrues a quarterly loss on its net profits
interest provided there is a cumulative net amount due for accrued revenue
as of the balance sheet date.
Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost method
of accounting for its oil and gas properties. The full cost method
subjects companies to quarterly calculations of a "ceiling", or limitation
on the amount of properties that can be capitalized on the balance sheet.
If the Partnership's capitalized costs are in excess of the calculated
ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
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.
Results of Operations
A. General Comparison of the Quarters Ended September 30, 2002 and 2001
The following table provides certain information regarding performance
factors for the quarters ended September 30, 2002 and 2001:
Three Months
Ended Percentage
September 30, Increase
2002 2001 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 26.16 22.46 16%
Average price per mcf of gas $ 2.61 2.53 3%
Oil production in barrels 1,450 1,600 (9%)
Gas production in mcf 13,700 20,000 (32%)
Income from net profits interests $ 24,839 33,528 (26%)
Partnership distributions $ 17,000 65,000 (74%)
Limited partner distributions $ 15,300 58,500 (74%)
Per unit distribution to limited partners $ 2.82 10.80 (74%)
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $24,839
from $33,528 for the quarters ended September 30, 2002 and 2001,
respectively, a decrease of 26%. The principal factors affecting the
comparison of the quarters ended September 30, 2002 and 2001 are as
follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended September 30, 2002 as compared to
the quarter ended September 30, 2001 by 16%, or $3.70 per barrel,
resulting in an increase of approximately $5,400 in income from net
profits interests. Oil sales represented 51% of total oil and gas
sales during the quarter ended September 30, 2002 as compared to 42%
during the quarter ended September 30, 2001.
The average price for an mcf of gas received by the Partnership
increased during the same period by 3%, or $.08 per mcf, resulting in
an increase of approximately $1,100 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
$6,500. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 150 barrels or 9% during the
quarter ended September 30, 2002 as compared to the quarter ended
September 30, 2001, resulting in a decrease of approximately $3,400 in
income from net profits interests.
Gas production decreased approximately 6,300 mcf or 32% during the same
period, resulting in a decrease of approximately $15,900 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $19,300. The decrease in gas
production is mainly due to downtime with a parted rod on one well
during the quarter ended September 30, 2002.
3. Lease operating costs and production taxes were 4% lower, or
approximately $2,300 less during the quarter ended September 30, 2002
as compared to the quarter ended September 30, 2001.
Costs and Expenses
Total costs and expenses decreased to $16,151 from $41,053 for the quarters
ended September 30, 2002 and 2001, respectively, a decrease of 61%. The
decrease is the result of lower depletion expense, partially offset by an
increase in 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 increased
11% or approximately $1,100 during the quarter ended September 30, 2002
as compared to the quarter ended September 30, 2001.
2. Depletion expense decreased to $5,000 for the quarter ended September
30, 2002 from $31,000 for the same period in 2001. This represents a
decrease of 84%. 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 decrease 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, 2002 as compared to 2001, and
the decrease in oil and gas revenues received by the Partnership during
2002 as compared to 2001.
B. General Comparison of the Nine Month Periods Ended September 30, 2002
and 2001
The following table provides certain information regarding performance
factors for the nine month periods ended September 30, 2002 and 2001:
Nine Months
Ended Percentage
September 30, Increase
2002 2001 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 22.76 23.46 (3%)
Average price per mcf of gas $ 2.52 4.32 (42%)
Oil production in barrels 4,500 5,100 (12%)
Gas production in mcf 49,000 60,100 (18%)
Income from net profits interests $ 94,935 201,247 (53%)
Partnership distributions $ 47,000 275,000 (83%)
Limited partner distributions $ 42,300 247,500 (83%)
Per unit distribution to limited partners $ 7.81 45.68 (83%)
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $94,935
from $201,247 for the nine months ended September 30, 2002 and 2001,
respectively, a decrease of 53%. The principal factors affecting the
comparison of the nine months ended September 30, 2002 and 2001 are as
follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the nine months ended September 30, 2002 as compared
to the nine months ended September 30, 2001 by 3%, or $.70 per barrel,
resulting in a decrease of approximately $3,200 1n income from net
profits interests. Oil sales represented 45% of total oil and gas
sales during the nine months ended September 30, 2002 as compared to
32% during the nine months ended September 30, 2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 42%, or $1.80 per mcf, resulting in
a decrease of approximately $88,200 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
$91,400. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 600 barrels or 12% during the
nine months ended September 30, 2002 as compared to the nine months
ended September 30, 2001, resulting in a decrease of approximately
$14,100 in income from net profits interests.
Gas production decreased approximately 11,100 mcf or 18% during the
same period, resulting in a decrease of approximately $48,000 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $62,100. The decrease in gas
production is mainly due to downtime with a parted rod on one well
during the nine months ended September 30, 2002.
3. Lease operating costs and production taxes were 26% lower, or
approximately $46,800 less during the nine months ended September 30,
2002 as compared to the nine months ended September 30, 2001. The
decrease in lease operating expense is due to repairs and maintenance
that was performed during the nine months ended September 30, 2001.
Costs and Expenses
Total costs and expenses decreased to $50,705 from $93,898 for the nine
months ended September 30, 2002 and 2001, respectively, a decrease of 46%.
The decrease is the result of lower depletion expense, partially offset by
an increase in 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 increased 3%
or approximately $800 during the nine months ended September 30, 2002
as compared to the nine months ended September 30, 2001.
2. Depletion expense decreased to $19,000 for the nine months ended
September 30, 2002 from $63,000 for the same period in 2001. This
represents a decrease of 70%. 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 decrease 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, 2002 as compared
to 2001, and the decrease in oil and gas revenues received by the
Partnership during 2002 as compared to 2001.
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 $50,300 in
the nine months ended September 30, 2002 as compared to approximately
$244,100 in the nine months ended September 30, 2001. The primary source
of the 2002 cash flow from operating activities was profitable operations.
Cash flows used in financing activities were approximately $47,000 in the
nine months ended September 30, 2002 as compared to approximately $275,000
in the nine months ended September 30, 2001. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 2002 were
$47,000 of which $42,300 was distributed to the limited partners and $4,700
to the general partners. The per unit distribution to limited partners
during the nine months ended September 30, 2002 was $7.81. Total
distributions during the nine months ended September 30, 2001 were $275,000
of which $247,500 was distributed to the limited partners and $27,500 to
the general partners. The per unit distribution to limited partners during
the nine months ended September 30, 2001 was $45.68.
The sources for the 2002 distributions of $47,000 were oil and gas
operations of approximately $50,300, resulting in excess cash for
contingencies or subsequent distributions. The source for the 2001
distributions of $275,000 was oil and gas operations of approximately
$244,100, with the balance from available cash on hand at the beginning of
the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $2,281,461 have been made to the partners. As of September 30, 2002,
$2,079,005 or $383.72 per limited partner unit has been distributed to the
limited partners, representing a 77% return of the capital contributed.
As of September 30, 2002, the Partnership had approximately $50,100 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.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged. The Managing General Partner is currently assessing the impact
on the partnerships financial statements.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets." This pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed" and eliminates the requirement of
Statement 121 to allocate goodwill to long-lived assets to be tested for
impairment. The provisions of this statement are effective for financial
statements issued for fiscal years beginning after December 15, 2001, and
interim periods within those fiscal years. The Managing General Partner
believes that the impact from SFAS No. 144 on the Partnerships financial
position and results of operation should not be significantly different
from that of SFAS No. 121.
In April 2002, FASB issued SFAS No. 145, "Rescission of SFAS No. 4, 44, and
64, Amendment of SFAS No. 13, and Technical Corrections." This Statement
rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt", and an amendment of that Statement, SFAS No. 64, "Extinguishments of
Debt Made to Satisfy Sinking-Fund Requirements". This Statement also
rescinds or amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their
applicability under changed conditions. This standard is effective for
fiscal years beginning after May 15, 2002. The Managing General Partner
believes that the adoption of this statement will not have a significant
impact on the Partnerships financial statements.
In July 2002, FASB issued SFAS No. 146 "Accounting for Costs Associated
with Exit or Disposal Activities" which establishes requirements for
financial accounting and reporting for costs associated with exit or
disposal activities. This standard is effective for exit or disposal
activities initiated after December 31, 2002. The Managing General Partner
is currently assessing the impact of this statement on the Partnerships'
future financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures. The chief
executive officer and chief financial officer of the Partnership's managing
general partner have evaluated the effectiveness of the design and
operation of the Partnership's disclosure controls and procedures (as
defined in Exchange Act Rule 13a-14(c)) as of a date within 90 days of the
filing date of this quarterly report. Based on that evaluation, the chief
executive officer and chief financial officer have concluded that the
Partnership's disclosure controls and procedures are effective to ensure
that material information relating to the Partnership and the Partnership's
consolidated subsidiaries is made known to such officers by others within
these entities, particularly during the period this quarterly report was
prepared, in order to allow timely decisions regarding required disclosure.
(b) Changes in Internal Controls. There have not been any significant
changes in the Partnership's internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation.
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) No reports on Form 8-K were filed during the quarter for
which this report is filed.
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-A, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
------------------------------
Bill E. Coggin, Executive Vice
President
and Chief Financial Officer
Date: November 14, 2002
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q of
Southwest Royalties Institutional Income Fund XI-A, L.P.;
2. Based on my knowledge, this quarterly report does not
contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund XI-A, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form 10-Q of
Southwest Royalties Institutional Income Fund XI-A, L.P.;
2. Based on my knowledge, this quarterly report does not
contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund XI-A, L.P.