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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 March 31, 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 14.
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, 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 month
period ended March 31, 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
March 31, December 31,
2002 2001
--------- ------------
(unaudited)
Assets
------
Current assets:
Cash and cash equivalents $ 14,350 22,949
Receivable from Managing General Partner 24,391 11,500
Distribution receivable 47 -
- --------- ---------
Total current assets
38,788 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
1,694,862 1,688,862
- --------- ---------
Net oil and gas properties
334,907 340,907
- --------- ---------
$
373,695 375,356
========= =========
Liabilities and Partners' Equity
--------------------------------
Current liability - distribution payable $ - 757
- --------- ---------
Partners' equity:
General partners (28,731) (29,241)
Limited partners 402,426 403,840
- --------- ---------
Total partners' equity
373,695 374,599
- --------- ---------
$
373,695 375,356
========= =========
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2002 2001
---- ----
Revenues
--------
Income from net profits interests $ 30,280 118,440
Interest 49 811
------- -------
30,329 119,251
------- -------
Expenses
--------
General and administrative 10,233 10,122
Depreciation, depletion and amortization 6,000 13,000
------- -------
16,233 23,122
------- -------
Net income $ 14,096 96,129
======= =======
Net income allocated to:
Managing General Partner $ 1,809 9,822
======= =======
General partner $ 201 1,091
======= =======
Limited partners $ 12,086 85,216
======= =======
Per limited partner unit $ 2.23 15.73
======= =======
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2002 2001
---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 28,963 136,909
Cash paid to suppliers (22,564) (12,610)
Interest received 49 811
-------- --------
Net cash provided by operating activities 6,448 125,110
-------- --------
Cash flows used in financing activities:
Distributions to partners (15,047) (120,000)
-------- --------
Net (decrease) increase in cash and cash equivalents (8,599)
5,110
Beginning of period 22,949 57,241
-------- --------
End of period $ 14,350 62,351
======== ========
Reconciliation of net income to net cash
provided by operating activities:
Net income $ 14,096 96,129
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization 6,000 13,000
(Increase) decrease in receivables (1,317) 18,469
Decrease in payables (12,331) (2,488)
------- -------
Net cash provided by operating activities $ 6,448 125,110
======= =======
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized
under the laws of the state of Delaware on May 5, 1992, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership will sell its oil
and gas production to a variety of purchasers with the prices it
receives being dependent upon the oil and gas economy. Southwest
Royalties, Inc. serves as the Managing General Partner and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partners Partners (1)
-------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital
contributions 100% -
Oil and gas revenues 90% 10%
Other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all 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 March 31, 2002, and for the
three months ended March 31, 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"
or "Registrant") 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, with the
offering of limited partnership interests concluding April 30, 1993. At
the conclusion of the offering of limited partnership interests, 217
limited partners had purchased 5,418 units for $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. As of March 31, 2002, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
Under the units of revenue method, the Partnership computes the provision
by multiplying the total unamortized cost of oil and gas properties by an
overall rate determined by dividing (a) oil and gas revenues during the
period by (b) the total future gross oil and gas revenues as estimated by
the Partnership's independent petroleum consultants. It is reasonably
possible that those estimates of anticipated future gross revenues, the
remaining estimated economic life of the product, or both could be changed
significantly in the near term due to the potential fluctuation of oil and
gas prices or production. The depletion estimate would also be affected by
this change.
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 March 31, 2002 and 2001
The following table provides certain information regarding performance
factors for the quarters ended March 31, 2002 and 2001:
Three Months
Ended Percentage
March 31, Increase
2002 2001 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 18.69 24.13 (23%)
Average price per mcf of gas $ 2.00 6.61 (70%)
Oil production in barrels 1,440 1,570 (8%)
Gas production in mcf 18,500 21,200 (13%)
Income from net profits interests $ 30,280 118,440 (74%)
Partnership distributions $ 15,000 120,000 (88%)
Limited partner distributions $ 13,500 108,000 (88%)
Per unit distribution to limited
partners $ 2.49 19.93 (88%)
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $30,280
from $118,440 for the quarters ended March 31, 2002 and 2001, respectively,
a decrease of 74%. The principal factors affecting the comparison of the
quarters ended March 31, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the quarter ended March 31, 2002 as compared to the
quarter ended March 31, 2001 by 23%, or $5.44 per barrel, resulting in
a decrease of approximately $7,800 in income from net profits
interests. Oil sales represented 42% of total oil and gas sales during
the quarter ended March 31, 2002 and 21% during quarter ended March 31,
2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 70%, or $4.61 per mcf, resulting in
a decrease of approximately $85,300 in income from net profits
interests.
The total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$93,100. 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 130 barrels or 8% during the
quarter ended March 31, 2002 as compared to the quarter ended March 31,
2001, resulting in a decrease of approximately $3,100 in income from
net profits interests.
Gas production decreased approximately 2,700 mcf or 13% during the same
period, resulting in a decrease of approximately $17,800 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $20,900.
3. Lease operating costs and production taxes were 43% lower, or
approximately $25,900 less during the quarter ended March 31, 2002 as
compared to the quarter ended March 31, 2001. The decrease in lease
operating expense is due to successful workovers performed in 2001, and
the decrease in production taxes in relation to the decrease n gross
revenues received in 2002.
Costs and Expenses
Total costs and expenses decreased to $16,233 from $23,122 for the quarters
ended March 31, 2002 and 2001, respectively, a decrease of 30%. 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 1%
or approximately $100 during the quarter ended March 31, 2002 as
compared to the quarter ended March 31, 2001.
2. Depletion expense decreased to $6,000 for the quarter ended March 31,
2002 from $13,000 for the same period in 2001. This represents a
decrease of 54%. 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 decrease in the price of gas used to determine the
Partnership's reserves for April 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 $6,400 in
the quarter ended March 31, 2002 as compared to approximately $125,100 in
the quarter ended March 31, 2001. The primary source of the 2002 cash flow
from operating activities was profitable operations.
Cash flows used in financing activities were $15,000 in the quarter ended
March 31, 2002 as compared to $120,000 in the quarter ended March 31, 2001.
The only use in financing activities was the distributions to partners.
Total distributions during the quarter ended March 31, 2002 were $15,000 of
which $13,500 was distributed to the limited partners and $1,500 to the
general partners. The per unit distribution to limited partners during the
quarter ended March 31, 2002 was $2.49. Total distributions during the
quarter ended March 31, 2001 were $120,000 of which $108,000 was
distributed to the limited partners and $12,000 to the general partners.
The per unit distribution to limited partners during the quarter ended
March 31, 2001 was $19.93.
The primary source for the 2002 distributions of $15,000 was oil and gas
operations of approximately $6,400, with the balance from available cash on
hand at the beginning of the period. The primary source for the 2001
distributions of $120,000 was oil and gas operations of approximately
$125,100, resulting in excess cash for contingencies or subsequent
distributions to partners.
Since inception of the Partnership, cumulative monthly cash distributions
of $2,249,461 have been made to the partners. As of March 31, 2002,
$2,050,205 or $378.41 per limited partner unit has been distributed to the
limited partners, representing a 76% return of the capital contributed.
As of March 31, 2002, the Partnership had approximately $38,800 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.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
$50.0 million and $123.7 million of principal due in August of 2003 and
October of 2004, respectively. The Managing General Partner will incur
approximately $17.6 million in interest payments in 2002 on its debt
obligations. Due to the depressed commodity prices experienced during the
last quarter of 2001, 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. Upon the
occurrence of any event of dissolution by the Managing General Partner, the
holders of a majority of limited partnership interests may, by written
agreement, elect to continue the business of the Partnership in the
Partnership's name, with Partnership property, in a reconstituted
partnership under the terms of the partnership agreement and to designate a
successor Managing General Partner. The Managing General Partner as of
April 19, 2002, successfully completed an exchange of a portion of their
bond debt for equity and performed a refinancing of its revolving credit
facility.
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 Statement 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. Assessment by the Managing
General Partner revealed this pronouncement to have no impact on the
partnerships.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
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) Reports on Form 8-K:
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, Vice President
and Chief Financial Officer
Date: May 15, 2002