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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [Fee Required]
For the fiscal year ended December 31, 2001
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required]
For the transition period from to
Commission File Number 33-47668-01
Southwest Royalties Institutional Income Fund XI-A, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2427297
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300, Midland, Texas 79701
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (915) 686-9927
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
limited partnership interests
Indicate by check mark whether registrant (1) has filed reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [x]
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 39. There is no
exhibit index.
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 6
3. Legal Proceedings 7
4. Submission of Matters to a Vote of Security Holders 7
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 8
6. Selected Financial Data 9
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 10
8. Financial Statements and Supplementary Data 18
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 33
Part III
10. Directors and Executive Officers of the Registrant 34
11. Executive Compensation 35
12. Security Ownership of Certain Beneficial Owners and
Management 35
13. Certain Relationships and Related Transactions 37
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 38
Signatures 39
Part I
Item 1. Business
General
Southwest Royalties Institutional Income Fund XI-A, L.P. (the "Partnership"
or "Registrant") was organized as a Delaware limited partnership on May 5,
1992. The offering of limited partnership interests began August 20, 1992,
as part of a shelf offering registered under the name Southwest Royalties
Institutional 1992-93 Income Program, reached minimum capital requirements
on December 10, 1992 and concluded April 30, 1993. The Partnership has no
subsidiaries.
The Partnership has acquired interests in producing oil and gas properties
and produced and marketed the crude oil and natural gas produced from such
properties. In most cases, the Partnership purchased royalty or overriding
royalty interests and working interests in oil and gas properties that were
converted into net profits interests or other non-operating interests. The
Partnership purchased either all or part of the rights and obligations
under various oil and gas leases.
The principal executive offices of the Partnership are located at 407 N.
Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner
of the Partnership, Southwest Royalties, Inc. (the "Managing General
Partner") and its staff of 89 individuals, together with certain
independent consultants used on an "as needed" basis, perform various
services on behalf of the Partnership, including the selection of oil and
gas properties and the marketing of production from such properties. H. H.
Wommack, III, a stockholder, director, President and Treasurer of the
Managing General Partner, is also a general partner. The Partnership has
no employees.
Principal Products, Marketing and Distribution
The Partnership has acquired and holds royalty interests and net profit
interests in oil and gas properties located in Alabama, Kansas, Louisiana,
New Mexico, Oklahoma and Texas. All activities of the Partnership are
confined to the continental United States. All oil and gas produced from
these properties is sold to unrelated third parties in the oil and gas
business.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. The prices received by
the Partnership for its oil and gas production depend upon numerous factors
beyond the Partnership's control, including competition, economic,
political and regulatory developments and competitive energy sources, and
make it particularly difficult to estimate future prices of oil and natural
gas.
For nearly nine months, despite the fears of a global recession, crude oil
prices held steady between $26 and $28 per barrel due in part to a series
of OPEC and non-OPEC production cuts. Then, following what has become
known simply as "9-11", crude prices plunged immediately to $22 and
gradually fell to below $18 per barrel. Slower demand across the U.S.
caused by the threat of recession and warmer than expected weather also led
to declining prices in the latter half of 2001. However, the oil cartel
and other non-member countries agreed for the fourth time since February to
curb output in an effort to stabilize prices. Crude oil contracts trading
on the NYMEX closed the year at approximately $20 per barrel.
Spot prices in 2001 climbed to their highest levels ever, with the yearly
average price nationwide reaching $4.14/MMBtu, up 9.77% from the 2000
average of $3.77/MMBtu. Prices reached their zenith in the first quarter
of 2001 before beginning a steady decline throughout the remainder of the
year. The terrorist attacks of September 11 knocked the New York
Mercantile Exchange out of the market for several days and shook the spot
marketplace into a maintenance mode. As companies measured the impact of
the attacks on the U.S. economy, spot prices deteriorated further. In the
fourth quarter, prices bottomed out for the year with the three-month
average falling to $2.31/MMBtu. As for 2002, record-high storage levels
and the expectation of a flat economy through the first half of the year
are leading industry experts to predict prices to average $2.05/MMBtu,
remaining above the $2.00 per MMBtu level for a 5th consecutive year.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
2001 31% 69%
2000 34% 66%
1999 37% 63%
As the table indicates, the majority of the Partnership's revenue is its
gas production, the Partnership revenues will be highly dependent upon the
future prices and demands for gas.
Seasonality of Business
Although the demand for natural gas is highly seasonal, with higher demand
in the colder winter months and in very hot summer months, the Partnership
has been able to sell all of its natural gas, either through contracts in
place or on the spot market at the then prevailing spot market price. As a
result, the volumes sold by the Partnership have not fluctuated materially
with the change of season.
Customer Dependence
No material portion of the Partnership's business is dependent on a single
purchaser, or a very few purchasers, where the loss of one would have a
material adverse impact on the Partnership. Three purchasers accounted for
76% of the Partnership's total oil and gas production during 2001: Sid
Richardson Energy Services for 44%, Navajo Refining Company, Inc. for 17%,
and Duke Energy Field Services for 15%. Three purchasers accounted for 81%
of the Partnership's total oil and gas production during 2000: Sid
Richardson Gasoline Co. for 37%, Navajo Refining Company, Inc. for 20% and
Phillips 66 for 24%. Four purchasers accounted for 80% of the Partnership's
total oil and gas production during 1999: Sid Richardson Gasoline Co. for
29%, Phillip 66 for 23%, Navajo Refining Company, Inc. for 18% and
Southwestern Energy Prod. Company for 10%. All purchasers of the
Partnership's oil and gas production are unrelated third parties. In the
event any of these purchasers were to discontinue purchasing the
Partnership's production, the Managing General Partner believes that a
substitute purchaser or purchasers could be located without undue delay.
No other purchaser accounted for an amount equal to or greater than 10% of
the Partnership's sales of oil and gas production.
Competition
Because the Partnership has utilized all of its funds available for the
acquisition of net profits or royalty interests in producing oil and gas
properties, it is not subject to competition from other oil and gas
property purchasers. See Item 2, Properties
Factors that may adversely affect the Partnership include delays in
completing arrangements for the sale of production, availability of a
market for production, rising operating costs of producing oil and gas and
complying with applicable water and air pollution control statutes,
increasing costs and difficulties of transportation, and marketing of
competitive fuels. Moreover, domestic oil and gas must compete with
imported oil and gas and with coal, atomic energy, hydroelectric power and
other forms of energy.
Regulation
Oil and Gas Production - The production and sale of oil and gas is subject
to federal and state governmental regulation in several respects, such as
existing price controls on natural gas and possible price controls on crude
oil, regulation of oil and gas production by state and local governmental
agencies, pollution and environmental controls and various other direct and
indirect regulation. Many jurisdictions have periodically imposed
limitations on oil and gas production by restricting the rate of flow for
oil and gas wells below their actual capacity to produce and by imposing
acreage limitations for the drilling of wells. The federal government has
the power to permit increases in the amount of oil imported from other
countries and to impose pollution control measures.
Various aspects of the Partnership's oil and gas activities will be
regulated by administrative agencies under statutory provisions of the
states where such activities are conducted and by certain agencies of the
federal government for operations on Federal leases. Moreover, certain
prices at which the Partnership may sell its natural gas production are
controlled by the Natural Gas Policy Act of 1978, the Natural Gas Wellhead
Decontrol Act of 1989 and the regulations promulgated by the Federal Energy
Regulatory Commission.
Environmental - The Partnership's oil and gas activities will be subject to
extensive federal, state and local laws and regulations governing the
generation, storage, handling, emission, transportation and discharge of
materials into the environment. Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties. This regulatory burden on the oil and gas industry increases
its cost of doing business and consequently affects its profitability. The
Managing General Partner is unable to predict what, if any, effect
compliance will have on the Partnership.
Industry Regulations and Guidelines - Industry regulations and guidelines
apply to the registration, qualification and operation of oil and gas
programs in the form of limited partnerships. The Partnership is subject
to these guidelines which regulate and restrict transactions between the
Managing General Partner and the Partnership. The Partnership complies
with these guidelines and the Managing General Partner does not anticipate
that continued compliance will have a material adverse effect on
Partnership operations.
Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a staff of geologists, engineers, accountants, landmen and clerical staff
who engage in Partnership activities and operations and perform additional
services for the Partnership as needed. In addition to the Managing
General Partner's staff, the Partnership engages independent consultants
such as petroleum engineers and geologists as needed. As of December 31,
2001, there were 89 individuals directly employed by the Managing General
Partner in various capacities.
Item 2. Properties
In determining whether an interest in a particular producing property was
to be acquired, the Managing General Partner considered such criteria as
estimated oil and gas reserves, estimated cash flow from the sale of
production, present and future prices of oil and gas, the extent of
undeveloped and unproved reserves, the potential for secondary, tertiary
and other enhanced recovery projects and the availability of markets.
As of December 31, 2001, the Partnership possessed an interest in oil and
gas properties located in Escambia and Lamar Counties of Alabama; Labette
and Neosho Counties of Kansas; La Fourche, Pointe Coupe and Terrebonne
Parishes of Louisiana; Eddy County of New Mexico; Custer, Roger Mills and
Washita Counties of Oklahoma; and Dewitt, Dickens, Fayette, Gaines,
Hemphill, Howard, Live Oak, Upton, Ward, Winkler, and Yoakum Counties of
Texas. These properties consist of various interests in 102 wells and
units.
Due to the Partnership's objective of maintaining current operations
without engaging in the drilling of any developmental or exploratory wells,
or additional acquisitions of producing properties, there have not been any
significant changes in properties during 2001 and 2000.
In compliance with the Partnership Agreement, if the Partnership should
purchase a producing property from the Managing General Partner, such
purchase price would be prior cost, adjusted for any intervening
operations. If such adjusted cost was greater than fair market value, or
if specific cost was unable to be determined, such purchase price would be
fair market value as determined by an independent reservoir engineer.
There were no property sales during 2001, 2000 and 1999.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and Location and Interest Wells Oil (bbls) Gas (mcf)
- ----------------- ----------- ----- --------- ---------
Custer & Wright 11/94 at 1% 27 17,000 309,000
Winkler County, to 40% net
Texas profits interests
Elizabeth Windham 10/94 at 28.9% 1 1,000 164,000
Upton County, Texas net profits
interests
*Ryder Scott Petroleum Engineers prepared the reserve and present value
data for the Partnership's existing properties as of January 1, 2002. The
reserve estimates were made in accordance with guidelines established by
the Securities and Exchange Commission pursuant to Rule 4-10(a) of
Regulation S-X. Such guidelines require oil and gas reserve reports be
prepared under existing economic and operating conditions with no
provisions for price and cost escalation except by contractual
arrangements.
Oil price adjustments were made in the individual evaluations to reflect
oil quality, gathering and transportation costs. The results of the reserve
report as of January 1, 2002 are an average price of $16.90 per barrel.
Gas price adjustments were made in the individual evaluations to reflect
BTU content, gathering and transportation costs and gas processing and
shrinkage. The results of the reserve report as of January 1, 2002 are an
average price of $2.12 per Mcf.
As also discussed in Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations, oil prices were subject to
frequent changes in 2001.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly with
respect to the quantity of oil or gas that any given property is capable of
producing. Estimates of oil and gas reserves are based on available
geological and engineering data the extent and quality of which may vary in
each case and, in certain instances, may prove to be inaccurate.
Consequently, properties may be depleted more rapidly than the geological
and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than
previously estimated; thus an ultimately lower return for the Partnership.
Basic changes in past reserve estimates occur annually. As new data is
gathered during the subsequent year, the engineer must revise his earlier
estimates. A year of new information, which is pertinent to the estimation
of future recoverable volumes, is available during the subsequent year
evaluation. In applying industry standards and procedures, the new data
may cause the previous estimates to be revised. This revision may increase
or decrease the earlier estimated volumes. Pertinent information gathered
during the year may include actual production and decline rates, production
from offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs, among
others. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing, proved developed non-producing and proved undeveloped. All of
the proved reserves are included in the engineering reports which evaluate
the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to farm-
out arrangements with the Managing General Partner or unrelated third
parties. Generally, the Partnership retains a carried interest such as an
overriding royalty interest under the terms of a farm-out, or receives
cash.
The Partnership or the owners of properties in which the Partnership owns
an interest can engage in workover projects or supplementary recovery
projects, for example, to extract behind the pipe reserves which qualify as
proved developed non-producing reserves. See Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth
quarter of 2001 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
Market Information
Limited partnership interests, or units, in the Partnership were initially
offered and sold for a price of $500. Limited partner units are not traded
on any exchange and there is no public or organized trading market for
them. The Managing General Partner has become aware of certain limited and
sporadic transfers of units between limited partners and third parties, but
has no verifiable information regarding the prices at which such units have
been transferred. Further, a transferee may not become a substitute
limited partner without the consent of the Managing General Partner.
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell. The
value of the unit is determined by adding the sum of (1) current assets
less liabilities and (2) the present value of the future net revenues
attributable to proved reserves and by discounting the future net revenues
at a rate not in excess of the prime rate charged by NationsBank, N.A. of
Midland, Texas plus one percent (1%), which value shall be further reduced
by a risk factor discount of no more than one-third (1/3) to be determined
by the Managing General Partner in its sole and absolute discretion. In
2001, 60 limited partner units were tendered to and purchased by the
Managing General Partner at an average base price of $143.28 per unit. In
2000, 14 limited partner units were tendered to and purchased by the
Managing General Partner at an average base price of $82.78 per unit. In
1999, 10 limited partner units were tendered to and purchased by the
Managing General Partner at an average base price of $108.72 per unit.
Number of Limited Partner Interest Holders
As of December 31, 2001, there were 220 holders of limited partner units in
the Partnership.
Distributions
Pursuant to Article III, Section 3.05 of the Partnership's Certificate and
Agreement of Limited Partnership, "Net Cash Flow" shall be distributed to
the partners on a quarterly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's investments in producing oil and gas
properties, less (i) General and Administrative Costs, (ii) Direct Costs,
(iii) Operating Costs, and (iv) any reserves necessary to meet current and
anticipated needs of the Partnership, as determined in the sole discretion
of the Managing General Partner."
During 2001, quarterly distributions were made totaling $295,018, with
$265,516 distributed to the limited partners and $29,502 to the general
partners. For the year ended December 31, 2001, distributions of $49.01
per limited partner unit were made, based upon 5,418 limited partner units
outstanding. During 2000, quarterly distributions were made totaling
$225,035, with $202,531 distributed to the limited partners and $22,504 to
the general partners. For the year ended December 31, 2000, distributions
of $37.38 per limited partner unit were made, based upon 5,418 limited
partner units outstanding. Distributions for 2000 increased significantly
due to the record high oil and gas prices received during the year. During
1999, distributions were made totaling $179,960, with $165,460 distributed
to the limited partners and $14,500 to the general partners. For the year
ended December 31, 1999, distributions of $30.54 per limited partner unit
were made, based upon 5,418 limited partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2001, 2000, 1999, 1998 and 1997 should be read in conjunction with the
financial statements included in Item 8:
Year ended December 31,
-------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Revenues $ 210,578 336,810 221,645 54,628 377,633
Net income (loss) 93,211 275,589 129,630(588,592)(133,264)
Partners' share of net
income (loss):
General partners 16,921 29,659 15,863 3,061 23,329
Limited partners 76,290 245,930 113,767(591,653)(156,593)
Limited partners' net
income (loss) per unit 14.08 45.39 21.00 (109.20)
(28.90)
Limited partners' cash
distribution per unit 49.01 37.38 30.54 30.20
61.14
Total assets $ 375,356 576,406 525,852 576,182 1,343,774
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized as a
Delaware limited partnership on May 5, 1992. The offering of limited
partnership interests began August 20, 1992, as part of a shelf offering
registered under the name Southwest Royalties Institutional 1992-93 Income
Program. Minimum capital requirements for the Partnership were met on
December 10, 1992, and the Offering Period terminated April 30, 1993 with
213 limited partners purchasing 5,418 units for $2,709,000.
The Partnership was formed to acquire non-operating interests in producing
oil and gas properties, to produce and market crude oil and natural gas
produced from such properties and to distribute any net proceeds from
operations to the general and limited partners. Net revenues from
producing oil and gas properties will not be reinvested in other revenue
producing assets except to the extent that producing facilities and wells
are reworked or where methods are employed to improve or enable more
efficient recovery of oil and gas reserves. The economic life of the
Partnership will thus depend on the period over which the Partnership's oil
and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore,
distributions to partners will depend primarily on changes in the prices
received for production, changes in volumes of production sold, lease
operating expenses, enhanced recovery projects, offset drilling activities
pursuant to farm-out arrangements and on the depletion of wells. Since
wells deplete over time, production can generally be expected to decline
from year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the limited
partners has fluctuated over the past few years and is expected to
fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing no workovers
during 2002 to enhance production. Additional workovers may be performed
in the year 2003. The partnership may have an increase in production
volumes for the year 2003, otherwise, the partnership will most likely
experience the historical production decline of approximately 9% per year.
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 Years Ended December 31, 2001 and 2000
The following table provides certain information regarding performance
factors for the years ended December 31, 2001 and 2000:
Year Ended Percentage
December 31, Increase
2001 2000 (Decrease)
---- ---- --------
Average price per barrel of oil $ 21.80 28.44 (23%)
Average price per mcf of gas $ 3.91 4.06 (4%)
Oil production in barrels 6,500 6,900 (6%)
Gas production in mcf 79,100 91,800 (14%)
Income from net profits interests $ 208,374 334,178 (38%)
Partnership distributions $ 295,018 225,035 31%
Limited partner distributions $ 265,516 202,531 31%
Per unit distribution to limited partners $ 49.01 37.38 31%
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $208,374
from $334,178 for the years ended December 31, 2001 and 2001, respectively,
a decrease of 38%. The principal factors affecting the comparison of the
years ended December 31, 2001 and 2000 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 2001 as compared to the
year ended December 31, 2000 by 23%, or $6.64 per barrel, resulting in
a decrease of approximately $43,200 in income from net profits
interests. Oil sales represented 31% of total oil and gas sales during
the year ended December 31, 2001 as compared to 34% during the year
ended December 31, 2000.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 4%, or $.15 per mcf, resulting in a
decrease of approximately $11,900 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
$55,100. 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 400 barrels or 6% during the
year ended December 31, 2001 as compared to the year ended December 31,
2000, resulting in a decrease of approximately $11,400 in income from
net profits interests.
Gas production decreased approximately 12,700 mcf or 14% during the
same period, resulting in a decrease of approximately $51,600 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $63,000.
3. Lease operating costs and production taxes were 3% higher, or
approximately $8,000 more during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
Costs and Expenses
Total costs and expenses increased to $117,367 from $61,221 for the years
ended December 31, 2001 and 2000, respectively, an increase of 92%. The
increase is the result of higher general and administrative costs and
depletion expense.
1. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 3%
or approximately $1,100 during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
2. Depletion expense increased to $76,000 for the year ended December 31,
2001 from $21,000 for the same period in 2000. This represents an increase
of 262%. 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.
The major factor to the increase in depletion expense between the
comparative periods was the decrease in the price of oil and gas used
to determine the Partnership's reserves for January 1, 2002 as compared
to 2001, and the decrease in oil and gas revenues received by the
Partnership during 2001 as compared to 2000. Revisions of previous
estimates can be attributed to the changes in production performance,
oil and gas price and production costs. The impact of the revision
would have increased depletion expense approximately $19,000 as of
December 31, 2000.
Results of Operations
B. General Comparison of the Years Ended December 31, 2000 and 1999
The following table provides certain information regarding performance
factors for the years ended December 31, 2000 and 1999:
Year Ended Percentage
December 31, Increase
2000 1999 (Decrease)
---- ---- --------
Average price per barrel of oil $ 28.44 16.56 72%
Average price per mcf of gas $ 4.06 2.26 80%
Oil production in barrels 6,900 8,390 (18%)
Gas production in mcf 91,800 105,480 (13%)
Income from net profits interests $ 334,178 198,794 68%
Partnership distributions $ 225,035 179,960 25%
Limited partner distributions $ 202,531 165,460 22%
Per unit distribution to limited partners $ 37.38 30.54 22%
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests increased to $334,178
from $198,794 for the years ended December 31, 2000 and 1999, respectively,
an increase of 68%. The principal factors affecting the comparison of the
years ended December 31, 2000 and 1999 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the year ended December 31, 2000 as compared to the
year ended December 31, 1999 by 72%, or $11.88 per barrel, resulting in
an increase of approximately $82,000 in income from net profits
interests. Oil sales represented 34% of total oil and gas sales during
the year ended December 31, 2000 as compared to 37% during the year
ended December 31, 1999.
The average price for an mcf of gas received by the Partnership
increased during the same period by 80%, or $1.80 per mcf, resulting in
an increase of approximately $165,200 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
$247,200. 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 1,490 barrels or 18% during the
year ended December 31, 2000 as compared to the year ended December 31,
1999, resulting in a decrease of approximately $24,700 in income from
net profits interests.
Gas production decreased approximately 13,680 mcf or 13% during the
same period, resulting in a decrease of approximately $30,900 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $55,600. The decrease in
production is due to the decline of several small non-operated wells.
3. Lease operating costs and production taxes were 31% higher, or
approximately $56,100 more during the year ended December 31, 2000 as
compared to the year ended December 31, 1999. The increase in lease
operating costs and production taxes is due in part to an increase in
major repairs and maintenance, and in part to the rise in production
taxes directly associated with the rise in oil and gas prices received
during the past year. The rise in oil and gas prices for 2000 has
allowed the Partnership to perform these repairs and maintenance in the
hopes of increasing production, thereby increasing revenues.
Costs and Expenses
Total costs and expenses decreased to $61,221 from $92,015 for the years
ended December 31, 2000 and 1999, respectively, a decrease of 33%. The
decrease is the result of lower general and administrative costs and
depletion expense.
1. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased 4%
or approximately $1,800 during the year ended December 31, 2000 as
compared to the year ended December 31, 1999.
3. Depletion expense decreased to $21,000 for the year ended December 31,
2000 from $50,000 for the same period in 1999. This represents a decrease
of 58%. 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.
The major factor to the decrease in depletion expense between the
comparative periods was the increase in the price of oil and gas used
to determine the Partnership's reserves for January 1, 2001 as compared
to 2000. Another contributing factor was due to the impact of
revisions of previous estimates on reserves. Revisions of previous
estimates can be attributed to the changes in production performance,
oil and gas price and production costs. The impact of the revision
would have decreased depletion expense approximately $3,000 as of
December 31, 1999.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2001, 2000 and 1999
was $93,211, $275,589 and $129,630, respectively. Excluding the effects of
depreciation, depletion and amortization, net income for the years ended
December 31, 2001, 2000 and 1999 would have been $169,211, $296,589 and
$179,630, respectively. Correspondingly, Partnership distributions for the
years ended December 31, 2001, 2000 and 1999 were $295,018, $225,035 and
$179,960, respectively. These differences are indicative of the changes in
oil and gas prices, production and properties during 2001, 2000 and 1999.
The sources for the 2001 distributions of $295,018 were oil and gas
operations of approximately $260,000, with the balance from available cash
on hand at the beginning of the period. The sources for the 2000
distributions of $225,035 were oil and gas operations of approximately
$252,100, resulting in excess cash for contingencies or subsequent
distributions. The sources for the 1999 distributions of $179,960 were oil
and gas operations of approximately $152,700, with the balance from
available cash on hand at the beginning of the period.
Total distributions during the year ended December 31, 2001 were $295,018
of which $265,516 was distributed to the limited partners and $29,502 to
the general partners. The per unit distribution to limited partners during
the same period was $49.01. Total distributions during the year ended
December 31, 2000 were $225,035 of which $202,531 was distributed to the
limited partners and $22,504 to the general partners. The per unit
distribution to limited partners during the same period was $37.38. Total
distributions during the year ended December 31, 1999 were $179,960 of
which $165,460 was distributed to the limited partners and $14,500 to the
general partners. The per unit distribution to limited partners during the
same period was $30.54.
Since inception of the Partnership, cumulative monthly cash distributions
of $2,234,461 have been made to the partners. As of December 31, 2001,
$2,036,705 or $375.91 per limited partner unit, has been distributed to the
limited partners, representing a 75% return of the capital contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
net profits interests in oil and gas properties. The Partnership knows of
no material change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $260,000 in
2001 compared to $252,100 in 2000 and approximately $152,700 in 1999. The
primary source of the 2001 cash flow from operating activities was
profitable operations.
There were no investing activities for 2001, 2000 and 1999.
Cash flows used in financing activities were approximately $294,300 in 2001
compared to $225,000 in 2000 and approximately $180,000 in 1999. The only
2001 use in financing activities was the distributions to partners.
As of December 31, 2001, the Partnership had approximately $33,700 in
working capital. The Managing General Partner knows of no other
commitments and believes the revenues generated from operations will be
adequate to meet the operating needs of the Partnership.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
$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.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No.133, "Accounting
for Derivative Instruments and Hedging Activities." SFAS No. 133, as
amended by SFAS No. 138, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded
in other contracts and for hedging activities. Assessment by the Managing
General Partner revealed this pronouncement to have no impact on the
partnerships.
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 is
currently assessing the impact to the partnerships financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Independent Auditors Report 18
Balance Sheets 19
Statements of Operations 20
Statement of Changes in Partners' Equity 21
Statements of Cash Flows 22
Notes to Financial Statements 24
INDEPENDENT AUDITORS REPORT
The Partners
Southwest Royalties Institutional
Income Fund XI-A, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Royalties
Institutional Income Fund XI-A, L.P. (the "Partnership") as of December 31,
2001 and 2000, and the related statements of operations, changes in
partners' equity and cash flows for each of the years in the three year
period ended December 31, 2001. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Royalties
Institutional Income Fund XI-A, L.P. as of December 31, 2001 and 2000 and
the results of its operations and its cash flows for each of the years in
the three year period ended December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas
March 10, 2002
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2001 and 2000
2001 2000
---- ----
Assets
------
Current assets:
Cash and cash equivalents $ 22,949 57,241
Receivable from Managing General Partner 11,500 102,258
- --------- ---------
Total current assets
34,449 159,499
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 2,029,769 2,029,769
Less accumulated depreciation,
depletion and amortization
1,688,862 1,612,862
- --------- ---------
Net oil and gas properties
340,907 416,907
- --------- ---------
$
375,356 576,406
========= =========
Liabilities and Partners' Equity
--------------------------------
Current liability - distribution payable $ 757 -
- --------- ---------
Partners' equity:
General partners (29,241) (16,660)
Limited partners 403,840 593,066
- --------- ---------
Total partners' equity
374,599 576,406
- --------- ---------
$
375,356 576,406
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Statements of Operations
Years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Revenues
--------
Income from net profits interests $ 208,374 334,178 198,794
Interest 2,204 2,632 1,851
-------
- ------- -------
210,578
336,810 221,645
-------
- ------- -------
Expenses
--------
General and administrative 41,367 40,221 42,015
Depreciation, depletion and amortization 76,000 21,000 50,000
-------
- ------- -------
117,367
61,221 92,015
-------
- ------- -------
Net income $ 93,211 275,589 129,630
=======
======= =======
Net income allocated to:
Managing General Partner $ 15,229 26,693 14,277
=======
======= =======
General partner $ 1,692 2,966 1,586
=======
======= =======
Limited partners $ 76,290 245,930 113,767
=======
======= =======
Per limited partner unit $ 14.08 45.39 21.00
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
Years ended December 31, 2001, 2000, 1999
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, 1998 $ (25,178) 601,360 576,182
Net income 15,863 113,767 129,630
Distributions (14,500) (165,460)(179,960)
-------
- --------- ---------
Balance at December 31, 1999 (23,815) 549,667 525,852
Net income 29,659 245,930 275,589
Distributions (22,504) (202,531)(225,035)
-------
- --------- ---------
Balance at December 31, 2000 (16,660) 593,066 576,406
Net income 16,921 76,290 93,211
Distributions (29,502) (265,516)(295,018)
-------
- --------- ---------
Balance at December 31, 2001 $ (29,241) 403,840 374,599
=======
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Cash flows from operating activities:
Cash received from net profits interests $ 289,364 294,075 163,960
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(31,599) (44,626)(13,062)
Interest received 2,204 2,632 1,851
---------
- --------- ---------
Net cash provided by operating activities 259,969 252,081
152,749
---------
- --------- ---------
Cash flows from financing activities:
Distributions to partners (294,261) (225,035)(179,960)
---------
- --------- ---------
Net (decrease) increase in cash and cash
equivalents (34,292) 27,046
(27,211)
Beginning of period 57,241 30,195 57,406
---------
- --------- ---------
End of period $ 22,949 57,241 30,195
=========
========= =========
(continued)
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows, continued
Years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Reconciliation of net income to net
cash provided by operating activities:
Net income $ 93,211 275,589 129,630
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation, depletion and amortization 76,000 21,000
50,000
Decrease (increase) in receivables 80,990 (40,103) (34,834)
Increase (decrease) in payables 9,768 (4,405) 7,953
-------
- ------- -------
Net cash provided by operating activities $ 259,969 252,081 152,749
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized
under the laws of the state of Delaware on May 5, 1992, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership will sell its oil
and gas production to a variety of purchasers with the prices it
receives being dependent upon the oil and gas economy. Southwest
Royalties, Inc. serves as the Managing General Partner and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partners Partners (1)
-------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital
contributions 100% -
Oil and gas revenues 90% 10%
Other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all costs of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to a Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
2. Summary of Significant Accounting Policies
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. Gain or loss on
the sale of oil and gas properties is not recognized unless
significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization
of oil and gas properties is computed under the units of revenue
method. Under the units of revenue method, depreciation, depletion
and amortization is computed on the basis of current gross revenues
from production in relation to future gross revenues, based on current
prices, from estimated production of proved oil and gas reserves.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Oil and Gas Properties - continued
Under the units of revenue method, the Partnership computes the
provision by multiplying the total unamortized cost of oil and gas
properties by an overall rate determined by dividing (a) oil and gas
revenues during the period by (b) the total future gross oil and gas
revenues as estimated by the Partnership's independent petroleum
consultants. It is reasonably possible that those estimates of
anticipated future gross revenues, the remaining estimated economic
life of the product, or both could be changed significantly in the
near term due to the potential fluctuation of oil and gas prices or
production. The depletion estimate would also be affected by this
change.
Should the net capitalized costs exceed the estimated present value of
oil and gas reserves, discounted at 10%, such excess costs would be
charged to current expense. As December 31, 2001, 2000 and 1999 the
net capitalized costs did not exceed the estimated present value of
oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net
profits interests in proved properties located within the continental
United States. A net profits interest is created when the owner of a
working interest in a property enters into an arrangement providing
that the net profits interest owner will receive a stated percentage
of the net profit from the property. The net profits interest owner
will not otherwise participate in additional costs and expenses of the
property.
Estimates and Uncertainties
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. The Partnerships depletion
calculation and full-cost ceiling test for oil and gas properties uses
oil and gas reserves estimates, which are inherently imprecise. Actual
results could differ from those estimates.
Syndication Costs
Syndication costs are accounted for as a reduction of partnership
equity.
Environmental Costs
The Partnership is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and
may require the Partnership to remove or mitigate the environmental
effects of the disposal or release of petroleum or chemical substances
at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Costs which
improve a property as compared with the condition of the property when
originally constructed or acquired and costs which prevent future
environmental contamination are capitalized. Expenditures that relate
to an existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for expenditures
of a non-capital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably
estimated.
Gas Balancing
The Partnership utilizes the sales method of accounting for gas-
balancing arrangements. Under this method, the Partnership recognizes
sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999
there were no significant amounts of imbalance in terms of units and
value.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," the
Partnership's tax basis in its net oil and gas properties at December
31, 2001 and 2000 is $434,772 and $427,018 more, respectively, as that
shown on the accompanying Balance Sheets in accordance with generally
accepted accounting principles.
Cash and Cash Equivalents
For purposes of the statements of cash flows, the Partnership
considers all highly liquid debt instruments purchased with a maturity
of three months or less to be cash equivalents. The Partnership
maintains its cash at one financial institution.
Number of Limited Partner Units
As of December 31, 2001, 2000 and 1999 there were 5,418 limited
partner units outstanding held by 220, 218 and 220 partners.
Concentrations of Credit Risk
The Partnership is subject to credit risk through trade receivables.
Although a substantial portion of its debtors' ability to pay is
dependent upon the oil and gas industry, credit risk is minimized due
to a large customer base. All partnership revenues are received by
the Managing General Partner and subsequently remitted to the
partnership and all expenses are paid by the Managing General Partner
and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair
value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No.133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS
No. 133, as amended by SFAS No. 138, establishes accounting and
reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging
activities. Assessment by the Managing General Partner revealed this
pronouncement to have no impact on the partnerships.
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 is currently assessing the impact
to the partnerships financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. 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.
4. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
shall be further reduced by a risk factor discount of no more than one-
third (1/3) to be determined by the Managing General Partner in its
sole and absolute discretion.
The Partnership is subject to various federal, state, and local
environmental laws and regulations, which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 2001, the Partnership has not been fined, cited or
notified of any environmental violations and management is not aware
of any unasserted violations which would have a material adverse
effect upon capital expenditures, earnings or the competitive position
in the oil and gas industry. However, the Managing General Partner
does recognize by the very nature of its business, material costs
could be incurred in the near term to bring the Partnership into total
compliance. The amount of such future expenditures is not reliably
determinable due to several factors, including the unknown magnitude
of possible contaminations, the unknown timing and extent of the
corrective actions which may be required, the determination of the
Partnership's liability in proportion to other responsible parties and
the extent to which such expenditures are recoverable from insurance
or indemnifications from prior owners of Partnership's properties.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As provided for in the operating agreement
for each respective oil and gas property in which the Partnership has
an interest, the operator is paid an amount for administrative
overhead attributable to operating such properties, with such amounts
to Southwest Royalties, Inc. as operator approximating $55,800,
$56,200 and $58,400 for the years ended December 31, 2001, 2000 and
1999, respectively. In addition, the Managing General Partner and
certain officers and employees may have an interest in some of the
properties that the Partnership also participates.
Certain subsidiaries or affiliates of the Managing General Partner
perform various oilfield services for properties in which the
Partnership owns an interest. Such services aggregated approximately
$9,500, $1,000 and $5,000 for the years ended December 31, 2001, 2000
and 1999, respectively.
Southwest Royalties, Inc., the Managing General Partner, was paid
$36,000 during 2001 and 2000 and $37,000 during 1999, as an
administrative fee for indirect general and administrative overhead
expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $11,500 and $102,300 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2001 and 2000.
In addition, a director and officer of the Managing General Partner is
a partner in a law firm, with such firm providing legal services to
the Partnership. There were no legal service provided to the
Partnership for the year ended December 31, 2001, 2000 and 1999.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchasers, where the loss of one
would have a material adverse impact on the Partnership. Three
purchasers accounted for 76% of the Partnership's total oil and gas
production during 2001: Sid Richardson Energy Services for 44%,
Navajo Refining Company, Inc. for 17%, and Duke Energy Field Services
for 15%. Three purchasers accounted for 81% of the Partnership's
total oil and gas production during 2000: Sid Richardson Gasoline Co.
for 37%, Navajo Refining Company, Inc. for 20% and Phillips 66 for
24%. Four purchasers accounted for 80% of the Partnership's total oil
and gas production during 1999: Sid Richardson Gasoline Co. for 29%,
Phillip 66 for 23%, Navajo Refining Company, Inc. for 18% and
Southwestern Energy Prod. Company for 10%. In the event any of these
purchasers were to discontinue purchasing the Partnership's
production, the Managing General Partner believes that a substitute
purchaser or purchasers could be located without undue delay. No
other purchaser accounted for an amount equal to or greater than 10%
of the Partnership's sales of oil and gas production.
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil (bbls) Gas (mcf)
---------- ---------
Proved developed and undeveloped
reserves -
January 1, 1999 27,000 763,000
Revision of estimates in place 51,000 206,000
Production (8,000) (105,000)
------- ---------
December 31, 1999 70,000 864,000
Revision of estimates in place 1,000 190,000
Production (7,000) (92,000)
------- ---------
December 31, 2000 64,000 962,000
Revision of estimates in place (20,000) (299,000)
Production (7,000) (79,000)
------- ---------
December 31, 2001 37,000 584,000
======= =========
Proved developed reserves -
December 31, 1999 70,000 855,000
======= =========
December 31, 2000 63,000 951,000
======= =========
December 31, 2001 37,000 574,000
======= =========
All of the Partnership's reserves are located within the continental
United States.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
*Ryder Scott Petroleum Engineers prepared the reserve and present
value data for the Partnership's existing properties as of January 1,
2002. The reserve estimates were made in accordance with guidelines
established by the Securities and Exchange Commission pursuant to Rule
4-10(a) of Regulation S-X. Such guidelines require oil and gas
reserve reports be prepared under existing economic and operating
conditions with no provisions for price and cost escalation except by
contractual arrangements.
Oil price adjustments were made in the individual evaluations to
reflect oil quality, gathering and transportation costs. The results
of the reserve report as of January 1, 2002 are an average price of
$16.90 per barrel.
Gas price adjustments were made in the individual evaluations to
reflect BTU content, gathering and transportation costs and gas
processing and shrinkage. The results of the reserve report as of
January 1, 2002 are an average price of $2.12 per Mcf.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing, proved developed non-producing and proved undeveloped. All
of the proved reserves are included in the engineering reports which
evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to
farm-out arrangements with the Managing General Partner or unrelated
third parties. Generally, the Partnership retains a carried interest
such as an overriding royalty interest under the terms of a farm-out,
or receives cash.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is
presented below:
2001 2000 1999
---- ---- ----
Future cash inflows, net of
production and development
costs $ 756,000 7,159,000 1,744,000
10% annual discount for
estimated timing of cash
flows 253,000 3,361,000 703,000
--------- --------- ---------
Standardized measure of
discounted future net cash
flows $ 503,000 3,798,000 1,041,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2001, 2000 and 1999 are as follows:
2001 2000 1999
---- ---- ----
Sales of oil and gas produced,
net of production costs $ (208,000) (334,000) (199,000)
Changes in prices and production costs (3,832,000) 2,524,000
309,000
Changes of production rates
(timing) and others 626,000 (90,000) (21,000)
Revisions of previous
quantities estimates (261,000) 553,000 415,000
Accretion of discount 380,000 104,000 49,000
Discounted future net
cash flows -
Beginning of year 3,798,000 1,041,000 488,000
--------- --------- ---------
End of year $ 503,000 3,798,000 1,041,000
========= ========= =========
Future net cash flows were computed using year-end prices and costs
that related to existing proved oil and gas reserves in which the
Partnership has mineral interests.
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
8. Selected Quarterly Financial Results - (unaudited)
Quarter
----------------------------------------------
First Second Third Fourth
------ ------- ------ ------
2001:
Total revenues $ 119,251 50,051 33,982 7,294
Total expenses 23,122 29,724 41,053 23,468
Net income (loss) 96,129 20,327 (7,071) (16,174)
Net income (loss) per limited
partners unit 15.73 3.03 (1.75) (2.93)
2000:
Total revenues $ 80,341 70,990 86,818 98,661
Total expenses 22,416 14,380 16,231 8,194
Net income (loss) 57,925 56,610 70,587 90,467
Net income (loss) per limited
partners unit 9.40 9.33 11.61 15.05
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None
Part III
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as
Managing General Partner. The names, ages, offices, positions and length
of service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below. Each director and executive officer serves for a
term of one year. The present directors of the Managing General Partner
have served in their capacity since the Company's formation in 1983.
Name Age Position
- -------------------- --- -----------------------------------
- -------
H. H. Wommack, III 46 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 45 Secretary and Director
Bill E. Coggin 47 Vice President and Chief
Financial Officer
J. Steven Person 43 Vice President, Marketing
Paul L. Morris 60 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive
Officer, Treasurer, principal stockholder and a director of the Managing
General Partner, and has served as its President since the Company's
organization in August, 1983. Prior to the formation of the Company, Mr.
Wommack was a self-employed independent oil producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases,
and the drilling of exploratory and developmental oil and gas wells. Mr.
Wommack holds a J.D. degree from the University of Texas from which he
graduated in 1980, and a B.A. from the University of North Carolina in
1977.
H. Allen Corey, a founder of the Managing General Partner, has served as
the Managing General Partner's secretary and a director since its
inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew
pub restaurant chain based in the Southeast. Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga, Tennessee. He is currently of counsel to the law firm of
Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga,
Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University
Law School and B.A. degree from the University of North Carolina at Chapel
Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with
the Managing General Partner since 1985. Mr. Coggin was Controller for Rod
Ric Corporation of Midland, Texas, an oil and gas drilling company, during
the latter part of 1984. He was Controller for C.F. Lawrence & Associates,
Inc., an independent oil and gas operator also of Midland, Texas during the
early part of 1984. Mr. Coggin taught public school for four years prior
to his business experience. Mr. Coggin received a B.S. in Education and a
B.B.A. in Accounting from Angelo State University.
J. Steven Person, Vice President, Marketing, assumed his responsibilities
with the Managing General Partner as National Marketing Director in 1989.
Prior to joining the Managing General Partner, Mr. Person served as Vice
President of Marketing for CRI, Inc., and was associated with Capital
Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor
University in 1982 and an M.B.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings,
Inc. since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States. Prior to
his position with Wagner & Brown, Mr. Morris served as President of Banner
Energy and in various managerial positions with the Columbia Gas System,
Inc.
Key Employees
Jon P. Tate, Vice President, Land and Assistant Secretary, age 44, assumed
his responsibilities with the Managing General Partner in 1989. Prior to
joining the Managing General Partner, Mr. Tate was employed by C.F.
Lawrence & Associates, Inc., an independent oil and gas company, as Land
Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin
Landman's Association and American Association of Petroleum Landmen. Mr.
Tate received his B.B.S. degree from Hardin-Simmons University.
R. Douglas Keathley, Vice President, Operations, age 46, assumed his
responsibilities with the Managing General Partner as a Production Engineer
in October, 1992. Prior to joining the Managing General Partner, Mr.
Keathley was employed for four (4) years by ARCO Oil & Gas Company as
senior drilling engineer working in all phases of well production (1988-
1992), eight (8) years by Reading & Bates Petroleum Company as senior
petroleum engineer responsible for drilling (1980-1988) and two (2) years
by Tenneco Oil Company as drilling engineer responsible for all phases of
drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum
Engineering in 1977 from the University of Oklahoma.
In certain instances, the Managing General Partner will engage professional
petroleum consultants and other independent contractors, including
engineers and geologists in connection with property acquisitions,
geological and geophysical analysis, and reservoir engineering. The
Managing General Partner believes that, in addition to its own "in-house"
staff, the utilization of such consultants and independent contractors in
specific instances and on an "as-needed" basis allows for greater
flexibility and greater opportunity to perform its oil and gas activities
more economically and effectively.
Item 11. Executive Compensation
The Partnership does not have any directors or executive officers. The
executive officers of the Managing General Partner do not receive any cash
compensation, bonuses, deferred compensation or compensation pursuant to
any type of plan, from the Partnership. The Managing General Partner
received $36,000 during 2001 as an annual administrative fee.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no limited partners who own of record, or are known by the
Managing General Partner to beneficially own, more than five percent of the
Partnership's limited partnership interests.
The Managing General Partner owns a nine percent interest in the
Partnership as a general partner. Through prior purchases, the Managing
General Partner also owns 410.0 limited partner units, or 7.6% limited
partner interest. The Managing General Partner total percentage interest
ownership in the Partnership is 15.8%.
No officer or director of the Managing General Partner owns Units in the
Partnership. H. H. Wommack, III, as the individual general partner of the
Partnership, owns a one percent interest as a general partner. The
officers and directors of the Managing General Partner are considered
beneficial owners of the limited partner units acquired by the Managing
General Partner by virtue of their status as such. A list of beneficial
owners of limited partner units, acquired by the Managing General Partner,
is as follows:
Amount and
Nature of Percent
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------------- --------------- -------
Limited Partnership Southwest Royalties, Inc. Directly Owns 7.6%
Interest Managing General Partner
410.0 Units
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns 7.6%
Interest Chairman of the Board,
410.0 Units
President, CEO, Treasurer
and Director of Southwest
Royalties, Inc., the
Managing General Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. Allen Corey Indirectly Owns 7.6%
Interest Secretary and Director of
410.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
633 Chestnut Street
Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns 7.6%
Interest Vice President and CFO of
410.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns 7.6%
Interest Vice President, Marketing
410.0 Units
of Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns 7.6%
Interest Director of Southwest
410.0 Units
Royalties, Inc., the
Managing General Partner
407 N. Big Spring Street
Midland, TX 79701
There are no arrangements known to the Managing General Partner which may
at a subsequent date result in a change of control of the Partnership.
Item 13. Certain Relationships and Related Transactions
In 2001, the Managing General Partners received $36,000 as an
administrative fee. This amount is part of the general and administrative
expenses incurred by the Partnership.
In some instances the Managing General Partner and certain officers and
employees may be working interest owners in an oil and gas property in
which the Partnership also has a working interest. Certain properties in
which the Partnership has an interest are operated by the Managing General
Partner, who was paid approximately $55,800 for administrative overhead
attributable to operating such properties during 2001.
Certain subsidiaries or affiliates of the Managing General Partner perform
various oilfield services for properties in which the Partnership owns an
interest. Such services aggregated approximately $9,500 for the year ended
December 31, 2001.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Independent Auditors Report
Balance Sheet
Statement of Operations
Statement of Changes in Partners' Equity
Statement of Cash Flows
Notes to Financial Statements
(2) Schedules required by Article 12 of
Regulation S-X are either omitted because they are not
applicable, or because the required information is shown
in the financial statements or the notes thereto.
(3) Exhibits:
4 (a) Certificate of Limited Partnership
of Southwest Royalties Institutional Income Fund
XI-A, L.P., dated May 5, 1992. (Incorporated by
reference from the Partnership's Form 10-K for
the fiscal year ended December 31, 1992.)
(b) Agreement of Limited Partnership
of Southwest Royalties Institutional Income Fund
XI-A, L.P., dated May 5, 1992. (Incorporated by
reference from the Partnership's Form 10-K for
the fiscal year ended December 31, 1992.)
(b) Report on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2001.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Partnership has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Royalties Institutional Income
Fund XI-A, L.P., a Delaware limited partnership
By: Southwest Royalties, Inc., Managing
General
Partner
By: /s/ H. H. Wommack, III
-----------------------------
H. H. Wommack, III,
President
Date: March 29, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III
-----------------------------------
H. H. Wommack, III, Chairman of the
Board, President, Chief Executive
Officer, Treasurer and Director
Date: March 29, 2002
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 29, 2002