FORM 10-K/A
AMENDMENT NO.1
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
For the fiscal year ended December 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 33-47668-02
Southwest Royalties Institutional Income Fund XI-B, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2427289
(State or other jurisdiction (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 (432) 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 No X
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K 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 50. The exhibit
index is found on page 47.
Table of Contents
Item Page
Part I
Glossary of Oil and Gas Terms 3
1. Business 5
2. Properties 9
3. Legal Proceedings 11
4. Submission of Matters to a Vote of Security Holders 11
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 12
6. Selected Financial Data 13
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 14
8. Financial Statements and Supplementary Data 21
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 37
Part III
10. Directors and Executive Officers of the Registrant 38
11. Executive Compensation 40
12. Security Ownership of Certain Beneficial Owners and
Management 40
13. Certain Relationships and Related Transactions 41
14. Controls and Procedures 41
Part IV
15. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 42
Signatures 43
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry that are used in this filing. All volumes of
natural gas referred to herein are stated at the legal pressure base to the
state or area where the reserves exit and at 60 degrees Fahrenheit and in
most instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42 United States gallons liquid volume.
Developmental well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir or to extend a known
reservoir.
Farm-out arrangement. An agreement whereby the owner of a leasehold or
working interest agrees to assign his interest in certain specific acreage
to an assignee, retaining some interest, such as an overriding royalty
interest, subject to the drilling of one (1) or more wells or other
specified performance by the assignee.
Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature and/or stratigraphic condition.
Mcf. One thousand cubic feet.
Net Profits Interest. An agreement whereby the owner receives a
specified percentage of the defined net profits from a producing property
in exchange for consideration paid. The net profits interest owner will
not otherwise participate in additional costs and expenses of the property.
Oil. Crude oil, condensate and natural gas liquids.
Overriding royalty interest. Interests that are carved out of a
working interest, and their duration is limited by the term of the lease
under which they are created.
Present value and PV-10 Value. When used with respect to oil and
natural gas reserves, the estimated future net revenue to be generated from
the production of proved reserves, determined in all material respects in
accordance with the rules and regulations of the SEC (generally using
prices and costs in effect as of the date indicated) without giving effect
to non-property related expenses such as general and administrative
expenses, debt service and future income tax expenses or to depreciation,
depletion and amortization, discounted using an annual discount rate of
10%.
Production costs. Costs incurred to operate and maintain wells and
related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of
operating and maintaining those wells and related equipment and facilities.
Proved Area. The part of a property to which proved reserves have been
specifically attributed.
Proved developed oil and gas reserves. Reserves that can be expected
to be recovered from existing wells with existing equipment and operating
methods.
Proved properties. Properties with proved reserves.
Proved oil and gas reserves. The estimated quantities of crude oil,
natural gas, and natural gas liquids with geological and engineering data
that demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made.
Proved undeveloped reserves. Reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required for recompletion.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil or gas that is confined by
impermeable rock or water barriers and is individual and separate from
other reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of
costs of production.
Working interest. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property
and a share of production.
Workover. Operations on a producing well to restore or increase
production.
Part I
Item 1. Business
General
Southwest Royalties Institutional Income Fund XI-B, L.P. (the "Partnership"
or "Registrant") was organized as a Delaware limited partnership on August
31, 1993. The offering of limited partnership interests began October 25,
1993, as part of a shelf offering registered under the name Southwest
Royalties Institutional 1992-93 Income Program. Minimum capital
requirements for the Partnership were met on December 8, 1993 and concluded
August 20, 1994. The Partnership has no subsidiaries.
As of December 31, 1996, the Partnership had utilized approximately
$2,008,600 of limited partner capital contributions to acquire interests in
oil and gas properties. All excess capital, $89,489, and the associated
organization costs of $3,132, had been distributed to the limited partners
in proportion to their capital contributions as a return of capital.
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 82 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, Chairman, Director, President and Chief Executive Officer of
the Managing General Partner, is also a general partner. The Partnership
has no employees.
Introductory Note
During 2002, the Partnership changed its method of providing for depletion
from the units-of-revenue method to the units-of-production method as
described in Note 3 to the Partnership's financial statements.
Subsequent to the issuance of the Annual Report on Form 10-K for the year
ended December 31, 2002, the Partnership determined that the above change
in accounting method should have been adopted by the Partnership as a
cumulative effect of a change in accounting principle. As described in
Note 9 to the Partnership's financial statements, the Partnership had
previously applied the change in the method of providing for depletion
prospectively as of October 1, 2002.
Principal Products, Marketing and Distribution
The Partnership has acquired and holds royalty interest and net profit
interests in oil and gas properties located in New Mexico 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. With some periodic
exceptions, since the early 1980's, there has been a worldwide oversupply
of oil; therefore, market prices have declined significantly. 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 for
oil and natural gas.
In 2002, fighting and threats of fighting in the Middle East and a strike
in a major oil exporting country dominated the direction of crude oil
prices. While OPEC agreed to keep production constant throughout the year,
conflicts between the U.S. and Iraq, as well as between Israel and the
Palestinians threatened supplies and caused oil prices to surge in 2002.
In addition, a strike by oil workers in Venezuela, the fourth largest
supplier to the U.S., took a significant amount of crude oil off the market
toward the end of the year. As a result, OPEC agreed in January 2003 to
increase output by 1.5 million barrels per day in an effort to make up for
the lost supply and stabilize prices.
In 2002, spot prices for natural gas fell by 27.5% from the unprecedented
heights reached in 2001, averaging just under $3.00/MMBtu for the year.
Most of the lowest prices were seen early on, with the first quarter
averaging of $2.24/MMBtu. But as the year progressed, prices climbed
higher, ending with a $3.99 average in December. As for 2003, industry
analysts are divided on their gas price predictions, with estimates ranging
anywhere from $4.00 to $6.00/MMBtu. Weather forecasts, storage inventory
levels, a tighter supply and demand balance, and the unstable situation
with Iraq are all factors that will have a significant impact on the
direction prices will take. Overall however, analysts are maintaining a
bullish perspective, expecting gas prices to remain at or above $4.00/MMBtu
in 2003.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
---- ----
2002 49% 51%
2001 37% 63%
2000 39% 61%
As the table indicates, the Partnership's revenue is almost evenly divided
between its oil and gas production. The Partnership revenues will be
highly dependent upon the future prices and demands for oil and gas.
Seasonality of Business
Although the demand for natural gas can be effected by seasonality, with
higher demand in the colder winter months and in very hot summer months,
the Partnership has not experienced material price and volume changes due
to seasonality and 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.
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. Two purchasers accounted for
82% of the Partnership's total oil and gas production during 2002: Sid
Richardson Energy Services. for 42% and Navajo Refining Company for 40%.
Contracts for 2002 with these major purchasers cover time periods ranging
from month to month contracts up to five-year contract periods. Prices
received from these major purchasers of $2.78 per mcf and $21.85 per
barrel. Three purchasers accounted for 93% of the Partnership's total
oil and gas production during 2001: Sid Richardson Energy Services for
52%, Navajo Refining Company for 31% and Duke Energy Field Services for
10%. Contracts for 2001 with these major purchasers cover time periods
ranging from month to month contracts up to five-year contract periods.
Prices received from these major purchasers ranged from a low of $4.38 per
mcf to a high of $4.43 per mcf and $24.90 per barrel. Three purchasers
accounted for 91% of the Partnership's total oil and gas production during
2000: Sid Richardson Gasoline Co. for 44%, Navajo Refining Company, Inc.
for 37% and Phillips 66 Natural Gas for 10%. Contracts for 2000 with these
major purchasers cover time periods ranging from month to month contracts
up to five-year contract periods. Prices received from these major
purchasers ranged from a low of $3.70 per mcf to a high of $3.71 per mcf
and $27.21 per barrel. 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 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 are 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. The regulatory burden on the oil and gas industry
increases the Partnership's cost of doing business, and, consequently,
affects its profitability.
Regulation of Sales and Transportation of Natural Gas. Our sales of
natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation
are subject to extensive regulation. In recent years, the FERC has
undertaken various initiatives to increase competition within the natural
gas industry. As a result of initiatives like FERC Order No. 636, issued in
April 1992, the interstate natural gas transportation and marketing system
has been substantially restructured to remove various barriers and
practices that historically limited non-pipeline natural gas sellers,
including producers, from effectively competing with interstate pipelines
for sales to local distribution companies and large industrial and
commercial customers. The most significant provisions of Order No. 636
require that interstate pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all
natural gas supplies. In many instances, the results of Order No. 636 and
related initiatives have been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. While the
United States Court of Appeals upheld most of Order No. 636, certain
related FERC orders, including the individual pipeline restructuring
proceedings, are still subject to judicial review and may be reversed or
remanded in whole or in part. While the outcome of these proceedings cannot
be predicted with certainty, we do not believe that we will be affected
materially differently than its competitors.
The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-
service rate making methodology to establish the rates interstate pipelines
may charge for their services. A number of pipelines have obtained FERC
authorization to charge negotiated rates as one such alternative. In
February 1997, the FERC announced a broad inquiry into issues facing the
natural gas industry to assist the FERC in establishing regulatory goals
and priorities in the post-Order No. 636 environment. Similarly, the Texas
Railroad Commission has been reviewing changes to its regulations governing
transportation and gathering services provided by intrastate pipelines and
gatherers. While the changes being considered by these federal and state
regulators would affect us only indirectly, they are intended to further
enhance competition in natural gas markets. We cannot predict what further
action the FERC or state regulators will take on these matters, however, we
do not believe that it will be affected by any action taken materially
differently than other natural gas producers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will
continue.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and gas liquids by us are not currently regulated and are made at market
prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market.
Environmental and Health Controls. Extensive federal, state and local
regulatory and common laws regulating the discharge of materials into the
environment or otherwise relating to the protection of the environment
affect our oil and natural gas operations. Numerous governmental
departments issue rules and regulations to implement and enforce such laws,
which are often difficult and costly to comply with and which carry
substantial civil and even criminal penalties for failure to comply. Some
laws, rules and regulations relating to protection of the environment may,
in certain circumstances, impose strict liability for environmental
contamination, rendering a person liable for environmental damages and
cleanup costs without regard to negligence or fault on the part of such
person. Other laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist or even
prohibit exploration and production activities in sensitive areas. In
addition, state laws often require various forms of remedial action to
prevent pollution, such as closure of inactive pits and plugging of
abandoned wells. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and consequently affects our
profitability. We believe that we are in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse
impact on our operations. However, environmental laws and regulations have
been subject to frequent changes over the years, and the imposition of more
stringent requirements could have a material adverse effect upon our
capital expenditures, earnings or competitive position. Additionally,
given the intense litigation environment in the United States, a threat
exists of lawsuits alleging personal injury and property damage from
environmental contamination alleged to be created by us or related
entities. Potential liability in such lawsuits can include not only
compensatory, but substantial punitive damages as well. We are not aware
of any such suits currently pending or threatened.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault on certain classes of persons that are considered to be
responsible for the release of a "hazardous substance" into the
environment. These persons include the current or former owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances. Under CERCLA
such persons may be subject to joint and several liability for the costs of
investigating and cleaning up hazardous substances that have been released
into the environment, for damages to natural resources and for the costs of
certain health studies. In addition, companies that incur liability
frequently also confront third party claims because it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by hazardous substances or
other pollutants released into the environment from a polluted site.
Potential liability also exists under CERCLA for natural resource damage.
A Natural Resource Damage Action (NRDA) could result in liability being
assessed for restoration to natural resources.
The Federal Oil Pollution Act of 1990 ("OPA") regulates the release of oil
into water or other areas designated by the statute. A release could
result in our being held responsible for the cost of remediating the
release, OPA specified damages and natural resource damages. The extent of
such liability could be extensive. A release of oil in harmful quantities
or other materials into water or other specified areas could also result in
our being held responsible under the Clean Water Act ("CWA") for the costs
of remediation, and any civil and criminal fines and penalties.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of solid and hazardous
wastes and can require cleanup of abandoned hazardous waste disposal sites
as well as waste management areas operating facilities. RCRA currently
excludes drilling fluids, produced waters and other wastes associated with
the exploration, development or production of oil and natural gas from
regulation as "hazardous waste." Disposal of such non-hazardous oil and
natural gas exploration, development and production wastes usually are
regulated by state law. Other wastes handled at exploration and production
sites or used in the course of providing well services may not fall within
this exclusion. Moreover, stricter standards for waste handling and
disposal may be imposed on the oil and natural gas industry in the future.
From time to time legislation is proposed in Congress that would revoke or
alter the current exclusion of exploration, development and production
wastes from the RCRA definition of "hazardous wastes" thereby potentially
subjecting such wastes to more stringent handling, disposal and cleanup
requirements. If such legislation were enacted it could have a significant
impact on the operating costs of Southwest and Sierra, as well as the oil
and natural gas industry and well servicing industry in general. The impact
of future revisions to environmental laws and regulations cannot be
predicted. In addition, if our operations were to trigger regulation under
RCRA, we could be required to satisfy certain financial criteria to ensure
financial ability to comply with RCRA regulations. Proof of financial
responsibility could be required in the form of dedicated trust funds,
irrevocable letters of credit, posting of bonds, etc.
The Federal Clean Water Act ("CWA") contains provisions that may result in
the imposition of certain water pollution control requirements with respect
to water releases from our operations. We may be required to incur certain
capital expenditures in the next several years for water pollution control
equipment in connection with obtaining and maintaining National Pollutant
Discharge Elimination Systems ("NPDES") permits. However, we believe our
operations will not be materially adversely affected by any such
requirements, and the requirements are not expected to be any more
burdensome to us than to other similarly situated companies involved in oil
and natural gas exploration and production activities or well surfacing
activities.
Our operations are also subject to the federal Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from
our operations. We may be required to incur certain capital expenditures in
the next several years for air pollution control equipment in connection
with obtaining and maintaining operating permits and approvals for air
emissions. However, we believe our operations will not be materially
adversely affected by any such requirements, and the requirements are not
expected to be any more burdensome to us than to other similarly situated
companies involved in oil and natural gas exploration and production
activities or well servicing activities.
We maintain insurance against "sudden and accidental" occurrences, which
may cover some, but not all, of the environmental risks described above.
Most significantly, the insurance we maintain will not cover the risks
described above which occur over a sustained period of time. Further, there
can be no assurance that such insurance will continue to be available to
cover all such costs or that such insurance will be available at premium
levels that justify its purchase. The occurrence of a significant event
not fully insured or indemnified against could have a material adverse
effect on our financial condition and operations.
Limited partners should be aware that the assessment of liability
associated with environmental liabilities is not always correlated to the
value of a particular project. Accordingly, liability associated with the
environment under local, state, or federal regulations, particularly clean
ups under CERCLA, can exceed the value of our investment in the associated
site.
Regulation of Oil and Natural Gas Exploration and Production. Our
exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulations
include requiring permits and drilling bonds for the drilling of wells,
regulating the location of wells, the method of drilling and casing wells,
and the surface use and restoration of properties upon which wells are
drilled. Many states also have statutes or regulations addressing
conservation matters, including provisions for the utilization or pooling
of oil and natural gas properties, the establishment of maximum rates of
production from oil and natural gas wells and the regulation of spacing,
plugging and abandonment of such wells. Some state statutes limit the rate
at which oil and natural gas can be produced from our properties.
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,
2002 there were 82 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, 2002, the Partnership possessed an interest in oil and
gas properties located in Eddy County of New Mexico; Andrews, Dawson,
Howard, Midland, Reeves, Schleicher, Upton, Ward and Winkler Counties of
Texas. These properties consist of various interests in 68 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 2002, 2001 and 2000.
There were no property sales during 2002 and 2000. During 2001, three
leases were sold for approximately $27,600.
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 operation.
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.
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 Wells Oil Gas
Interest (bbls) (mcf)
- ----------------- ----------- ------ -------- --------
- - -
Custer & Wright 11/94 at 28 21,000 271,000
Winkler County, Texas 1% to 40% 27 21,000(1 261,000(
) 1)
net profits
interests
Michael Dingman 9/94 at 38 20,000 63,000
Midland, Reeves, .5% to 50% 33 18,000(1 57,000(1
Dawson, Schleicher, ) )
Winkler Ward, Andrews, net profits
Counties, interests
Texas; Eddy County, New
Mexico
(1)Amounts represent proved developed reserves from currently producing
zones.
*Ryder Scott Company, L.P. prepared the reserve and present value data for
the Partnership's existing properties as of January 1, 2003. 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, 2003 are an average price of $28.59 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, 2003 are an
average price of $4.46 per Mcf.
As also discussed in Part II, Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations, oil and gas prices were
subject to frequent changes in 2002.
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 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 farmout
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.
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. See Part II,
Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operation.
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 2002 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 are currently
being 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. 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. As of
December 31, 2002, 2001 and 2000, no limited partner units were purchased
by the Managing General Partner. Southwest, as Managing General Partner,
evaluated several liquidity alternatives for the partnerships in 2001 and
2002. During 2002, Southwest specifically pursued the possible roll-up and
merger of twenty-one (21) partnerships with the general partner. Because
of the complexities and conflicts of interest in such a transaction, the
Managing General Partner did not make a formal repurchase offer in 2002 but
has responded to limited partners desiring to sell their units in the
partnerships on an "as requested" basis. Southwest anticipates that it
will not make a formal repurchase offer during 2003 because the merger is
still being contemplated and Southwest's Registration Statement on Form S-4
relating to the merger is still in the review process with the Securities
and Exchange Commission. Repurchases by Southwest, however, will continue
to be made on an "as requested" basis.
Number of Limited Partner Interest Holders
As of December 31, 2002, there were 177 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 2002, distributions were made totaling $67,616, with $61,805
distributed to the limited partners and $5,811 to the general partners. For
the year ended December 31, 2002, distributions of $12.74 per limited
partner unit were made, based upon 4,851 limited partner units outstanding.
During 2001, distributions were made totaling $260,419, with $234,377
distributed to the limited partners and $26,042 to the general partners.
For the year ended December 31, 2001, distributions of $48.32 per limited
partner unit were made, based upon 4,851 limited partner units outstanding.
During 2000, quarterly distributions were made totaling $235,737, with
$212,163 distributed to the limited partners and $23,574 to the general
partners. For the year ended December 31, 2000, distributions of $43.74
per limited partner unit were made, based upon 4,851 limited partner units
outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31 2002,
2001, 2000, 1999 and 1998 should be read in conjunction with the financial
statements included in Item 8:
Years ended December 31,
-----------------------------------------------
2002 2001 2000 1999 1998
(Restate
d)(1)
---- ---- ---- ---- ----
Revenues $ 106,519 227,624 305,760 210,376 2,205
Net income (loss)
before cumulative 42,971 128,334 249,986 129,693 (462,692
effect )
Net income (loss) 48,971 128,334 249,986 129,693 (462,692
)
Partners' share of
net income (loss):
General partners 6,597 18,734 26,699 16,880 (4,631)
Limited partners 42,374 109,600 223,287 112,814 (458,061
)
Limited partners' net
income (loss) per unit
before cumulative 7.50
effect 22.59 46.03 23.26 (94.43)
Limited partners' net
income (loss) per unit 8.74
22.59 46.03 23.26 (94.43)
Limited partner's cash
distribution per unit 12.74
48.32 43.74 20.94 10.85
Total assets $ 269,090 287,587 419,672 405,423 388,507
(1) See Notes 3 and 9 to the Partnership's financial statements for a
description of the Partnership's change in accounting principle.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized as a
Delaware limited partnership on August 31, 1993. The offering of limited
partnership interests began October 25, 1993, as part of a shelf offering
registered under the name Southwest Royalties Institutional 1992-93 Income
Program. Minimum capital requirements for the Partnership were met on
December 8, 1993, and the Offering Period terminated August 20, 1994 with
174 limited partners purchasing 4,851 units for $2,425,500.
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 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 2003 to enhance production. Additional workovers may be performed
in the year 2004. The partnership may have an increase in production
volumes for the year 2004; otherwise, the partnership will most likely
experience the historical production decline, which have approximated 11%
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.
In the fourth quarter of 2002, the Partnership changed methods of
accounting for depletion of capitalized costs from the units-of-revenue
method to the units-of-production method. The newly adopted accounting
principle is preferable in the circumstances because the units-of-
production method results in a better matching of the costs of oil and gas
production against the related revenue received in periods of volatile
prices for production as have been experienced in recent periods.
Additionally, the units-of-production method is the predominant method used
by full cost companies in the oil and gas industry, accordingly, the change
improves the comparability of the Partnership's financial statements with
its peer group. The effect of this change in method was to increase 2002
depletion expense by $2,000 and increase 2002 net income by $4,000. See
Note 3 of the notes to the Partnership's financial statements.
Results of Operations
A. General Comparison of the Years Ended December 31, 2002 and 2001
The following table provides certain information regarding performance
factors for the years ended December 31, 2002 and 2001:
Year Ended Percenta
ge
December 31, Increase
2002 2001 (Decreas
e)
---- ---- --------
-
Average price per barrel $ 24.31 (5%)
of oil 25.48
Average price per mcf of $ 2.91 (27%)
gas 3.99
Oil production in 5,820 6,130 (5%)
barrels
Gas production in mcf 49,800 67,500 (26%)
Income from net profits $ 106,272 225,266 (53%)
interests
Partnership $ 67,616 260,419 (74%)
distributions
Limited partner $ 61,805 234,377 (74%)
distributions
Per unit distribution to $ 12.74 (74%)
limited partners 48.32
Number of limited 4,851 4,851
partner units
Revenues
The Partnership's income from net profits interests decreased to $106,272
from $225,266 for the years ended December 31, 2002 and 2001, respectively,
a decrease of 53%. The principal factors affecting the comparison of the
years ended December 31, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 2002 as compared to the
year ended December 31, 2001 by 5%, or $1.17 per barrel, resulting in a
decrease of approximately $6,800 in income from net profits interests.
Oil sales represented 49% of total oil and gas sales during the year
ended December 31, 2002 as compared to 37% during the year ended
December 31, 2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 27%, or $1.08 per mcf, resulting in
a decrease of approximately $53,800 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
$60,600. The market price for oil and gas has been extremely volatile
over the past decade and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 310 barrels or 5% during the
year ended December 31, 2002 as compared to the year ended December 31,
2001, resulting in a decrease of approximately $7,900 in income from
net profits interests.
Gas production decreased approximately 17,700 mcf or 26% during the
same period, resulting in a decrease of approximately $70,600 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $78,500. The decrease in gas
production is due primarily to one lease that had been shut-in during
the year, but is currently being brought back on.
3. Lease operating costs and production taxes were 10% lower, or
approximately $20,600 less during the year ended December 31, 2002 as
compared to the year ended December 31, 2001.
Costs and Expenses
Total costs and expenses decreased to $63,548 from $99,290 for the years
ended December 31, 2002 and 2001, respectively, a decrease of 36%. The
decrease is the result of lower depletion expense, partially offset by an
increase in general and administrative costs.
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 $300 during the year ended December 31, 2002 as
compared to the year ended December 31, 2001.
2. Depletion expense decreased to $23,000 for the year ended December 31,
2002 from $59,000 for the same period in 2001. This represents a
decrease of 61%. In the fourth quarter of 2002, the Partnership
changed methods of accounting for depletion of capitalized costs from
the units-of-revenue method to the units-of-production method. The
newly adopted accounting principle is preferable in the circumstances
because the units-of-production method results in a better matching of
the costs of oil and gas production against the related revenue
received in periods of volatile prices for production as have been
experienced in recent periods. Additionally, the units-of-production
method is the predominant method used by full cost companies in the oil
and gas industry, accordingly, the change improves the comparability of
the Partnership's financial statements with its peer group. The effect
of this change in method was to increase 2002 depletion expense by
$2,000 and increase 2002 net income by $4,000. See Note 3 of the notes
to the Partnership's financial statements.
The major factor in 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, 2003 as compared
to 2002, which provided more economically recoverable proved reserves
at January 1, 2003 which caused the depletion rate per equivalent unit
produced to decline. Also, as discussed above, the total equivalent
units produced in 2002 declined from 2001.
Results of Operations
B. 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 Percenta
ge
December 31, Increase
2001 2000 (Decreas
e)
---- ---- --------
-
Average price per barrel $ 25.48 (11%)
of oil 28.50
Average price per mcf of $ 3.99 (4%)
gas 4.14
Oil production in barrels 6,130 6,800 (10%)
Gas production in mcf 67,500 73,300 (8%)
Income from net profits $ 225,266 303,558 (26%)
interests
Partnership distributions $ 260,419 235,737 10%
Limited partner $ 234,377 212,163 10%
distributions
Per unit distribution to $ 48.32 10%
limited partners 43.74
Number of limited partner 4,851 4,851
units
Revenues
The Partnership's income from net profits interests decreased to $225,266
from $303,558 for the years ended December 31, 2001 and 2000, respectively,
a decrease of 26%. 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 11%, or $3.02 per barrel, resulting in
a decrease of approximately $18,500 in income from net profits
interests. Oil sales represented 37% of total oil and gas sales during
the year ended December 31, 2001 as compared to 39% 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 $10,100 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
$28,600. The market price for oil and gas has been extremely volatile
over the past decade and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 670 barrels or 10% during the
year ended December 31, 2001 as compared to the year ended December 31,
2000, resulting in a decrease of approximately $19,100 in income from
net profits interests.
Gas production decreased approximately 5,800 mcf or 8% during the same
period, resulting in a decrease of approximately $24,000 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $43,100.
3. Lease operating costs and production taxes were 4% higher, or
approximately $6,800 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 $99,290 from $55,774 for the years
ended December 31, 2001 and 2000, respectively, an increase of 78%. The
increase is the result of higher depletion expense and general and
administrative costs.
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 4%
or approximately $1,500 during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
2. Depletion expense increased to $59,000 for the year ended December 31,
2001 from $17,000 for the same period in 2000. This represents an
increase of 247%. 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 in 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 $27,000 as of
December 31, 2000.
C. Revenue and Distribution Comparison
Partnership income for the years ended December 31, 2002, 2001 and 2000 was
$48,971, $128,334 and $249,986, respectively. Excluding the effects of
depreciation, depletion and amortization, net income would have been
$71,971 in 2002, $187,334 in 2001 and $266,986 in 2000. Correspondingly,
Partnership distributions for the years ended December 31, 2002, 2001 and
2000 were $67,616, $260,419 and $235,737, respectively. These differences
are indicative of the changes in oil and gas prices, production and
property.
The sources for the 2002 distributions of $67,616 were oil and gas
operations of approximately $48,800, with the balance from available cash
on hand at the beginning of the period. The source for the 2001
distributions of $260,419 were oil and gas operations of approximately
$231,800, and the change in oil and gas properties of approximately
$27,600, with the balance from available cash on hand at the beginning of
the period. The source for the 2000 distributions of $235,737 was oil and
gas operations of approximately $247,300, resulting in excess cash for
contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2002 were $67,616 of
which $61,805 was distributed to the limited partners and $5,811 to the
general partners. The per unit distribution to limited partners during the
same period was $12.74. Total distributions during the year ended December
31, 2001 were $260,419 of which $234,377 was distributed to the limited
partners and $26,042 to the general partners. The per unit distribution to
limited partners during the same period was $48.32. Total distributions
during the year ended December 31, 2000 were $235,737 of which $212,163 was
distributed to the limited partners and $23,574 to the general partners.
The per unit distribution to limited partners during the same period was
$43.74.
Since inception of the Partnership, cumulative monthly cash contributions
of $1,665,910 have been made to the partners. As of December 31, 2002,
$1,514,297 or $312.16 per limited partner unit has been distributed to the
limited partners, representing a 62% return of 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 $48,800 in
2002 compared to $231,800 in 2001 and approximately $247,300 in 2000. The
primary source of the 2002 cash flow from operating activities was
profitable operations.
There were no cash flows provided by investing activities in 2002. Cash
flows provided by investing activities were approximately $27,600 in 2001.
The Partnership had no cash flows from investing activities in 2000.
Cash flows used in financing activities were approximately $67,500 in 2002
compared to $260,400 in 2001 and approximately $235,700 in 2000. The only
2002 use in financing activities was the distribution to partners.
As of December 31, 2002, the Partnership had approximately $48,900 in
working capital. The Managing General Partner knows of no other
commitments. Although the Partnership held many long-lived properties at
inception, because of the restrictions on property development imposed by
the partnership agreement, the Partnership cannot develop its non producing
properties, if any. Without continued development, the producing reserves
continue to deplete. Accordingly, as the Partnership's properties have
matured and depleted, the net cash flows from operations for the
Partnership has steadily declined, except in periods of substantially
increased commodity pricing. Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production. As the
properties continue to deplete, maintenance of properties and
administrative costs as a percentage of production are expected to continue
to increase.
The Managing General Partner has examined various alternatives to address
the issue of depleting producing reserves. Continuing operations exposes
the Partnership to an inevitable decline in operating results and
distributions of cash. Liquidating the Partnership would result in
immediate realization of cash for limited partners, but prices paid by
purchasers of Partnership property in liquidation would likely include a
substantial discount for risks and uncertainties of future cash flows, as
well as any development risks. After reviewing various alternatives, we
initiated a plan to merge the Partnership and 20 other limited partnerships
with and into the Managing General Partner. On October 17, 2002, the
Managing General Partner filed a Registration Statement on form S-4 with
the Securities and Exchange Commission relating to this proposed merger.
There is no assurance, however, that this merger will be consummated.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
approximately $124.0 million of principal due between December 31, 2002 and
December 31, 2004. The Managing General Partner is constantly monitoring
its cash position and its ability to meet its financial obligations as they
become due, and in this effort, is continually exploring various strategies
for addressing its current and future liquidity needs. The Managing
General Partner regularly pursues and evaluates recapitalization strategies
and acquisition opportunities (including opportunities to engage in
mergers, consolidations or other business combinations) and at any given
time may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to fund
debt service, developmental projects and day to day operations, but it is
not sufficient to build a cash balance which would allow the Managing
General Partner to meet its debt principal maturities scheduled for 2004.
Therefore the Managing General Partner is currently seeking to renegotiate
the terms of its obligations, including extending maturity dates, or to
engage new lenders or equity investors in order to satisfy its financial
obligations maturing in 2004.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful. In the event these efforts are
unsuccessful, the Managing General Partner would need to look to other
alternatives to meet its debt obligations, including potentially selling
its assets. There can be no assurance, however, that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Please see the Partnership's Quarterly Report on Form 10-
Q for the quarterly period ended September 30, 2003, which will be filed
with the Commission on or before November 14, 2003, for updated information
on the liquidity of the Managing General Partner. The liquidity of the
Managing General Partner, however, does not have a material impact on the
operations of the Partnership. The partnership agreement of the
Partnership allows the limited partners to elect a successor managing
general partner to continue Partnership operations.
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 new standard requires the Partnership to recognize a
liability for the present value of all legal obligations associated with
the retirement of tangible long-lived assets and to capitalize an equal
amount as a cost of the asset and allocate the additional cost over the
estimated useful life of the asset. On January 1, 2003, the Partnership
recorded additional costs, net of accumulated depreciation, depletion and
amortization, of approximately $52,752, a long term liability of
approximately $123,875 and a loss of approximately $71,123 for the
cumulative effect on depreciation, depletion and amortization of the
additional costs and accretion expense on the liability related to expected
abandonment costs of its oil and natural gas producing properties.
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 22
Balance Sheets 23
Statements of Operations 24
Statements of Changes in Partners' Equity 25
Statements of Cash Flows 26
Notes to Financial Statements 27
INDEPENDENT AUDITORS REPORT
The Partners
Southwest Royalties Institutional
Income Fund XI-B, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Royalties
Institutional Income Fund XI-B, L.P. (the "Partnership") as of December 31,
2002 and 2001, 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, 2002. 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-B, L.P. as of December 31, 2002 and 2001 and
the results of its operations and its cash flows for each of the years in
the three year period ended December 31, 2002 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Notes 3 and 9 to the financial statements, the Partnership
changed its method of computing depletion in 2002.
KPMG LLP
Midland, Texas
March 14, 2003, except as to Notes 3, 9 and 10, which is as of July 11,
2003
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2002 and 2001
2002 2001
(Restate
d)
---- ----
Assets
- ---------
Current assets:
Cash and cash equivalents $ 16,742 35,398
Receivable from Managing 32,324 15,165
General Partner
-------- --------
----- ----
Total current assets 49,066 50,563
-------- --------
----- ----
Oil and gas properties -
using the full-
cost method of accounting 1,978,74 1,978,74
5 5
Less accumulated
depreciation,
depletion and 1,758,72 1,741,72
amortization 1 1
-------- --------
----- ----
Net oil and gas 220,024 237,024
properties
-------- --------
----- ----
$ 269,090 287,587
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- -----------
Current liability - $ 148 -
distribution payable
-------- --------
--- ----
Partners Equity:
General partners 3,181 2,395
Limited partners 265,761 285,192
-------- --------
----- ----
Total partners' equity 268,942 287,587
-------- --------
----- ----
$ 269,090 287,587
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Operations
Years ended December 31, 2002, 2001 and 2000
2002 2001 2000
(Restate
d)
---- ---- ----
Revenues
- ------------
Income from net profits $ 106,272 225,266 303,558
interests
Interest from operations 247 2,358 2,202
-------- -------- --------
-- -- --
106,519 227,624 305,760
-------- -------- --------
-- -- --
Expenses
- ------------
General and administrative 40,548 40,290 38,774
Depreciation, depletion and 23,000 59,000 17,000
amortization
-------- -------- --------
-- -- --
63,548 99,290 55,774
-------- -------- --------
-- -- --
Net income before cumulative 42,971 128,334 249,986
effect
Cumulative effect of change 6,000 - -
in accounting principle
-------- -------- --------
-- -- --
Net income $ 48,971 128,334 249,986
====== ====== ======
Net income allocated to:
Managing General Partner $ 5,937 16,860 24,029
====== ====== ======
General Partner $ 660 1,874 2,670
====== ====== ======
Limited partners $ 42,374 109,600 223,287
====== ====== ======
Per limited partner unit $ 7.50
before cumulative effect 22.59 46.03
Cumulative effect per 1.24 - -
limited partner unit
-------- -------- --------
-- -- --
Per limited partner unit $ 8.74
22.59 46.03
====== ======= =======
Pro forma amounts assuming
change is applied
retroactively (See Note 3):
Net income before $ - 148,334 236,986
cumulative effect
====== ======= =======
Per limited partner unit $ - 26.72 43.35
(4,851.0 units)
====== ======= =======
Net income $ - 148,334 236,986
====== ======= =======
Per limited partner unit $ - 26.72 43.35
(4,851.0 units)
====== ======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Changes in Partners' Equity
Years ended December 31, 2002, 2001 and 2000
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, $ 6,578 398,845 405,423
1999
Net income 26,699 223,287 249,986
Distributions (23,574) (212,163 (235,737
) )
-------- -------- --------
-- --- ---
Balance at December 31, 9,703 409,969 419,672
2000
Net income 18,734 109,600 128,334
Distributions (26,042) (234,377 (260,419
) )
-------- -------- --------
-- --- ---
Balance at December 31, 2,395 285,192 287,587
2001
Net income (Restated) 6,597 42,374 48,971
Distributions (5,811) (61,805) (67,616)
-------- -------- --------
-- ---- ----
Balance at December 31, $ 3,181 265,761 268,942
2002 (Restated)
====== ======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2002, 2001 and 2000
2002 2001 2000
(Restate
d)
---- ---- ----
Cash flows from operating
activities:
Cash received from net $ 96,659 265,384 284,309
profits interests
Cash paid to Managing General
Partner
for administrative fees and
general
and administrative overhead (48,094) (35,960) (39,182)
Interest received 247 2,358 2,202
-------- -------- --------
-- -- --
Net cash provided by 48,812 231,782 247,329
operating activities
-------- -------- --------
-- -- --
Cash flows from investing
activities:
Sales of oil and gas - 27,589 -
properties
-------- -------- --------
-- -- --
Cash flows used in financing
activities:
Distributions to partners (67,468) (260,419 (235,667
) )
-------- -------- --------
-- -- --
Net (decrease) increase in
cash and cash
equivalents (18,656) (1,048) 11,662
Beginning of period 35,398 36,446 24,784
-------- -------- --------
-- -- --
End of period $ 16,742 35,398 36,446
====== ====== =====
Reconciliation of net income
to net
cash provided by operating
activities:
Net income $ 48,971 128,334 249,986
Adjustments to reconcile net
income to
net cash provided by
operating activities:
Depreciation, depletion and 23,000 59,000 17,000
amortization
Cumulative effect of change (6,000) - -
in accounting principle
(Increase) decrease in (9,613) 40,118 (19,249)
receivables
(Decrease) increase in (7,546) 4,330 (408)
payables
-------- -------- --------
-- -- --
Net cash provided by operating $ 48,812 231,782 247,329
activities
====== ====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized
under the laws of the state of Delaware on August 31, 1993, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership will sell its oil
and gas production to a variety of purchasers with the prices it
receives being dependent upon the oil and gas economy. Southwest
Royalties, Inc. serves as the Managing General Partner and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partner Partners
(1)
------- --------
Organization and offering 100% -
expenses (2)
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on
capital
contributions 100% -
Oil and gas revenues 90% 10%
All other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to the Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenue; 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.
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. In applying the units-of-revenue method
for the years ended December 31, 2001, 2000 and for the nine months
ended September 30, 2002, we have not excluded royalty and net profit
interest payments from gross revenues as all of our royalty and net
profit interests have been purchased and capitalized to the depletion
basis of our proved oil and gas properties. As of December 31, 2002,
2001 and 2000, the net capitalized costs did not exceed the estimated
value of oil and gas reserves.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Oil and Gas Properties - continued
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. 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. As of December 31,
2002, there were no timing differences, which resulted in a deficit
net profit interest.
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.
Revenue Recognition
We recognize oil and gas sales when delivery to the purchaser has
occurred and title has transferred. This occurs when production has
been delivered to a pipeline or transport vehicle.
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, 2002, 2001 and
2000, there were no significant amounts of imbalance in terms of units
or value.
Southwest Royalties Institutional Income Fund XI-B, 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 oil and gas properties at December 31,
2002 and 2001 is $402,758 and $437,324 more than that shown on the
accompanying Balance Sheet in accordance with generally accepted
accounting principles.
Cash and Cash Equivalents
For purposes of the statement 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, 2002, 2001 and 2000 there were 4,851 limited
partner units outstanding held by 177 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
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 new standard requires the Partnership to
recognize a liability for the present value of all legal obligations
associated with the retirement of tangible long-lived assets and to
capitalize an equal amount as a cost of the asset and allocate the
additional cost over the estimated useful life of the asset. On
January 1, 2003, the Partnership recorded additional costs, net of
accumulated depreciation, depletion and amortization, of approximately
$52,752, a long term liability of approximately $123,875 and a loss of
approximately $71,123 for the cumulative effect on depreciation,
depletion and amortization of the additional costs and accretion
expense on the liability related to expected abandonment costs of its
oil and natural gas producing properties.
Depletion Policy
In 2002, the Partnership changed methods of accounting for depletion
of capitalized costs from the units-of-revenue method to the units-of-
production method. (See Note 3)
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Cumulative effect of a change in accounting principle
In the fourth quarter of 2002, the Partnership changed methods of
accounting for depletion of capitalized costs from the units-of-
revenue method to the units-of-production method. The newly adopted
accounting principle is preferable in the circumstances because the
units-of-production method results in a better matching of the costs
of oil and gas production against the related revenue received in
periods of volatile prices for production as have been experienced in
recent periods. Additionally, the units-of-production method is the
predominant method used by full cost companies in the oil and gas
industry, accordingly, the change improves the comparability of the
Partnership's financial statements with its peer group. The
Partnership adopted the units-of-production method through the
recording of a cumulative effect of a change in accounting principle
in the amount of $6,000 effective as of January 1, 2002. The
Partnership's depletion for the year ended 2002 has been calculated
using the units-of-production method and prior years have not been
restated. The pro forma amounts for 2001 and 2000, which are
presented on the face of the statements of operations, reflect the
effect of retroactive application of the units-of-production method.
The effect of the change on the year ended December 31, 2002 was to
decrease income before cumulative effect of a change in accounting
principle by $2,000 ($.41 per limited partner unit) and increase net
income by $4,000 ($.83 per limited partner unit). See Note 10 for the
effects of the change in depletion method on the individual quarters
of 2002.
4. Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure
with approximately $124.0 million of principal due between December
31, 2002 and December 31, 2004. The Managing General Partner is
constantly monitoring its cash position and its ability to meet its
financial obligations as they become due, and in this effort, is
continually exploring various strategies for addressing its current
and future liquidity needs. The Managing General Partner regularly
pursues and evaluates recapitalization strategies and acquisition
opportunities (including opportunities to engage in mergers,
consolidations or other business combinations) and at any given time
may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to
fund debt service, developmental projects and day to day operations,
but it is not sufficient to build a cash balance which would allow the
Managing General Partner to meet its debt principal maturities
scheduled for 2004. Therefore the Managing General Partner is
currently seeking to renegotiate the terms of its obligations,
including extending maturity dates, or seek new lenders or equity
investors in order to satisfy its financial obligations maturing in
2004.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful. In the event these efforts
are unsuccessful, the Managing General Partner would need to look to
other alternatives to meet its debt obligations, including potentially
selling its assets. There can be no assurance, however, that the
sales of assets can be successfully accomplished on terms acceptable
to the Managing General Partner. Please see the Partnership's
Quarterly Report on Form 10-Q for the quarterly period ended September
30, 2003, which will be filed with the Commission on or before
November 14, 2003, for updated information on the liquidity of the
Managing General Partner. The liquidity of the Managing General
Partner, however, does not have a material impact on the operations of
the Partnership. The partnership agreement of the Partnership allows
the limited partners to elect a successor managing general partner to
continue Partnership operations.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. 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.
Southwest, as Managing General Partner, evaluated several liquidity
alternatives for the partnerships in 2001 and 2002. During 2002,
Southwest specifically pursued the possible roll-up and merger of
twenty-one (21) partnerships with the general partner. Because of the
complexities and conflicts of interest in such a transaction, the
Managing General Partner did not make a formal repurchase offer in
2002 but has responded to limited partners desiring to sell their
units in the partnerships on an "as requested" basis. Southwest
anticipates that it will not make a formal repurchase offer during
2003 because the merger is still being contemplated and Southwest's
Registration Statement of Form S-4 relating to the merger is still in
the review process with the Securities and Exchange Commission.
Repurchases by Southwest, however, will continue to be made on an "as
requested" basis.
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, 2002, 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-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. 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 $55,400,
$56,800 and $55,500 for the years ended December 31, 2002, 2001 and
2000, respectively. The amounts for administrative overhead
attributable to operating the partnership properties have been
deducted from gross oil and gas revenues in the determination of net
profit interest. 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
$2,800,4,100 and $2,500 for the years ended December 31, 2002, 2001
and 2000, respectively. The amounts for oilfield services performed
for the partnership by affiliates of the Managing General Partner have
been deducted from gross oil and gas revenues in the determination of
net profit interest.
Southwest Royalties, Inc., the Managing General Partner, was paid
$34,800 in 2002, 2001 and 2000, as an administrative fee for indirect
general and administrative overhead expenses. The administrative fees
are included in general and administrative expense on the statement of
operations.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $32,324 and $15,165 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2002 and 2001, respectively.
7. 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. Two
purchasers accounted for 82% of the Partnership's total oil and gas
production during 2002: Sid Richardson Energy Services. for 42% and
Navajo Refining Company for 40%. Contracts for 2002 with these major
purchasers cover time periods ranging from month to month contracts up
to five-year contract periods. Prices received from these major
purchasers of $2.78 per mcf and $21.85 per barrel. Three purchasers
accounted for 93% of the Partnership's total oil and gas production
during 2001: Sid Richardson Energy Services for 52%, Navajo Refining
Company for 31% and Duke Energy Field Services for 10%. Contracts for
2001 with these major purchasers cover time periods ranging from month
to month contracts up to five-year contract periods. Prices received
from these major purchasers ranged from a low of $4.38 per mcf to a
high of $4.43 per mcf and $24.90 per barrel. Three purchasers
accounted for 91% of the Partnership's total oil and gas production
during 2000: Sid Richardson Gasoline Co. for 44%, Navajo Refining
Company, Inc. for 37% and Phillips 66 Natural Gas for 10%. Contracts
for 2000 with these major purchasers cover time periods ranging from
month to month contracts up to five-year contract periods. Prices
received from these major purchasers ranged from a low of $3.70 per
mcf to a high of $3.71 per mcf and $27.21 per barrel. 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.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
8. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil Gas
(bbls) (mcf)
-------- --------
-- -
Total Proved -
January 1, 2000 62,000 784,000
Revisions of previous 13,000 85,000
estimates
Production (7,000) (73,000)
-------- --------
-- ---
December 31, 2000 68,000 796,000
Sales of reserves in place (2,000) (10,000)
Revisions of previous (33,000) (226,000
estimates )
Production (6,000) (68,000)
-------- --------
-- ---
December 31, 2001 27,000 492,000
Revisions of previous 21,000 (39,000)
estimates
Production (6,000) (50,000)
-------- --------
-- ---
December 31, 2002 42,000 403,000
====== =======
Proved developed reserves -
December 31, 2000 67,000 783,000
====== =======
December 31, 2001 27,000 479,000
====== =======
December 31, 2002 41,000 390,000
====== =======
All of the Partnership's reserves are located within the continental
United States.
*Ryder Scott Company, L.P. prepared the reserve and present value data
for the Partnership's existing properties as of January 1, 2003. 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, 2003 are an average price of
$28.59 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, 2003 are an average price of $4.46 per Mcf.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
8. Estimated Oil and Gas Reserves (unaudited) - continued
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
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.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
8. 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, 2002, 2001 and 2000 is
presented below:
2002 2001 2000
---- ---- ----
Future cash inflows $ 2,979,00 1,561,00 9,618,00
0 0 0
Production and development 1,568,00 936,000 3,604,00
costs 0 0
-------- -------- --------
-- -- ----
Future net cash flows 1,411,00 625,000 6,014,00
0 0
10% annual discount for
estimated timing of cash
flows 544,000 207,000 2,793,00
0
-------- -------- --------
--- -- ----
Standardized measure of
discounted future net cash
flows $ 867,000 418,000 3,221,00
0
====== ====== =======
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2002, 2001 and 2000 are as follows:
2002 2001 2000
---- ---- ----
Sales of oil and gas
produced,
net of production costs $ (106,000 (225,000 (303,000
) ) )
Changes in prices and 439,000 (3,104,0 2,174,00
production costs 00) 0
Changes of production rates
(timing) and others (41,000) 507,000 (64,000)
Revisions of previous
quantities estimates 115,000 (279,000 436,000
)
Accretion of discount 42,000 322,000 89,000
Sales of minerals in place - (24,000) -
Discounted future net
cash flows -
Beginning of year 418,000 3,221,00 889,000
0
-------- -------- --------
-- ---- ----
End of year $ 867,000 418,000 3,221,00
0
====== ======= =======
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-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
9. December 31, 2002 Restatement
During 2002, the Partnership changed its method of providing for
depletion from the units-of-revenue method to the units-of-production
method as described in Note 3.
Subsequent to the issuance of the Partnership's Annual Report on Form
10-K for the year ended December 31, 2002, the Partnership determined
that the above change in accounting method should have been adopted by
the Partnership as a cumulative effect of a change in accounting
principle. The Partnership had previously applied the change in the
method of providing for depletion prospectively as of October 1, 2002.
This change in the method used to implement the Partnership's change
in the manner in which it determines depletion resulted in an increase
in the Partnership's previously reported net oil and gas properties of
$4,000 from $216,024 to $220,024 as of December 31, 2002 and did not
effect the Partnership's 2002 cash flows from operations, investing or
financing activities.
The change had the following effects on the Statement of Operations
for the year ended December 31, 2002. (Periods prior to 2002 were not
affected by the change).
Restated Previously
Reported
Depreciation, depletion and $23,000 21,000
amortization
Income before cumulative effect 42,971 44,971
Cumulative effect of change in 6,000 -
accounting principle
Net income 48,971 44,971
Net income allocated to:
Managing General Partner 5,937 5,937
General partner 660 660
Limited partners 42,374 38,374
Income per limited partner
unit before
cumulative effect 7.50 7.91
Cumulative effect per 1.24 -
limited partner unit
Net income per limited 8.74 7.91
partner unit
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
10. Selected Quarterly Financial Results - (unaudited)
As discussed in Note 3, in 2002 the Partnership changed methods of
accounting for depletion of capitalized costs from the units-of-
revenue method to the units-of-production method. The 2002 quarterly
financial results presented below have been restated to reflect the
change in depletion method effective as of January 1, 2002. See Notes
3 and 9 for a detailed discussion of the change in depletion method.
Quarter
--------------------------------------
--------------------------------------
-
First Second Third Fourth
------ -------- ------- --------
--- -
2002:
Total revenues $ 18,999 37,371 16,154 33,995
Total expenses as 14,891 15,686 15,051 15,920
originally reported
Effect of change in 2,000 - - -
depletion method
Total expenses restated 16,891 15,686 15,051 15,920
-------- -------- -------- --------
---- ---- ---- ----
Net income as originally 4,108 21,685 1,103 18,075
reported
Income before cumulative
effect of
a change in accounting 2,108 21,685 1,103 18,075
principle
Cumulative effect on
prior years (to
December 31, 2001) of
changing to a
different depletion 6,000 - - -
method
-------- -------- -------- --------
---- ---- ---- ----
Net income as restated $ 8,108 21,685 1,103 18,075
======= ======= ======= =======
Per limited partner unit
amounts:
Net income originally $ .66 .12
reported 3.90 3.23
Effect of change in - - -
depletion method (.41)
-------- -------- -------- --------
---- ---- ---- ----
Income before cumulative
effect of a
change in accounting .25 .12
principle 3.90 3.23
Cumulative effect on
prior years (to
December 31, 2001) of
changing to a
different depletion 1.24 - - -
method
-------- -------- -------- --------
---- ---- ---- ----
Net income as restated $ 1.49 .12
3.90 3.23
======= ======= ======= =======
2001:
Total revenues $ 100,024 69,479(1 27,023 31,097
)
Total expenses 19,747 25,448 33,967 20,128
Net income (loss) 80,277 44,031 (6,944) 10,969
Net income (loss) per
limited
partners unit 14.69
7.86 (1.78) 1.82
(1) Due to a clerical error total revenues and net income differ by $14,492
from amounts previously reported in the Form 10-Q for June 30, 2001. The
previously reported six-month amounts were unaffected.
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 of the
Managing General Partner serves for a term of one year.
Name Age Position
H. H. Wommack, III 47 Chairman of the Board,
President, Director
and Chief Executive Officer
James N. Chapman(1) 40 Director
William P. Nicoletti(2) 57 Director
Joseph J. Radecki, Jr. 44 Director
(2)
Richard D. Rinehart(1) 67 Director
John M. White(2) 46 Director
Herbert C. Williamson, 54 Director
III(1)
Bill E. Coggin 48 Executive Vice President and
Chief Financial Officer
J. Steven Person 44 Vice President, Marketing
(1) Member of the Compensation Committee
(2) Member of the Audit Committee
H. H. Wommack, III has served as Chairman of the Board, President, Chief
Executive Officer and a director since Southwest's founding in 1983. Since
1997 Mr. Wommack has served as President, Chief Executive Officer and
Chairman of SRH, Southwest's former parent and current holder of 10% of its
voting share capital. SRH holds an equity investment in Southwest and in
Basic Energy Services. Since 1997 Mr. Wommack has served as chairman of
the board of directors of Midland Red Oak Realty, Inc. Midland Red Oak
Realty owns and manages commercial real estate properties, including
shopping centers and office buildings, in secondary real estate markets in
the Southwestern United States. From 1997 until December 2000, Mr. Wommack
served as chairman of the board of directors of Basic Energy Services, Inc.
and since December 2000 has continued to serve on Basic's board of
directors. Basic provides certain well services for oil and gas companies.
Prior to Southwest's formation, Mr. Wommack was a self-employed independent
oil and gas producer engaged in the purchase and sale of royalty and
working interests in oil and gas leases and the drilling of wells. Mr.
Wommack graduated from the University of North Carolina at Chapel Hill and
received his law degree from the University of Texas.
James N. Chapman has served as a director since April 19,2002. Mr. Chapman
has been involved in the investment banking industry for 18 years. Since
January 2002 he has acted as a capital markets and strategic planning
consultant with private and public companies across a range of industries,
including metals, mining, manufacturing, aerospace, airline, service and
healthcare. Prior to establishing an independent consulting practice, from
1997 to 2002 Mr. Chapman worked for The Renco Group, Inc., a multi-billion
private corporation in New York, for which Mr. Chapman developed and
implemented financing and merger and acquisitions strategies for Renco's
diverse portfolio of companies. From 1990 to 1997, Mr. Chapman was a
founding principal of Fieldstone Private Capital Group, a capital markets
advisory firm. From 1985 to 1990, Mr. Chapman worked for Bankers Trust
Company, most recently in the BT Securities Capital Markets area. Mr.
Chapman received an MBA degree with distinction from the Amos Tuck School
at Dartmouth College and was elected an Edward Tuck Scholar. He received
his BA degree with distinction magna cum laude, at Dartmouth College, was
elected to Phi Beta Kappa and was a Rufus Choate Scholar.
William P. Nicoletti has served as a director since April 19, 2002. Mr.
Nicoletti is Managing Director of Nicoletti & Company Inc., an investment
banking and financial advisory firm he founded in 1991. He was previously
a senior officer and head of the Energy Investment Banking Groups of E. F.
Hutton & Company Inc. and Paine Webber, Incorporated. From March 1998
until June 1990 he was a managing director and co-head of Energy Investment
Banking at McDonald Investments Inc. Mr. Nicoletti has been Chairman of
the board of directors of Russell-Stanley Holdings, Inc., a manufacturer
and marketer of steel and plastic industrial containers since November
2001. He is a director of Mark WestEnergy Partners, L.P., a business
engaged in the gathering and processing of natural gas and the
fractionation and storage of natural gas liquids. Mr. Nicoletti is also a
Director and Chairman of the Audit Committee of Star Gas Partners, L.P.,
the nation's largest retail distributor of home heating oil and a major
retail distributor of propane gas. Mr. Nicoletti is a graduate of Seton
Hall University and received an MBA degree from Columbia University
Graduate School of Business.
Joseph J. Radecki, Jr. has served as a director since April 19, 2002. Mr.
Radecki is currently a Managing Director in the Leveraged Finance Group of
CIBC World Markets where he is principally responsible for the firm's
financial restructuring and distressed situation advisory practice. Prior
to joining CIBC World Markets in 1998, Mr. Radecki was an Executive Vice
President and Director of the Financial Restructuring Group of Jefferies &
Company, Inc. beginning in 1990. From 1983 until 1990, Mr. Radecki was
First Vice President in the International Capital Markets Group at Drexel
Burnham Lambert, Inc., where he specialized in financial restructurings and
recapitalizations. Over the past fourteen years, Mr. Radecki has been
integrally involved in over 120 transactions totaling nearly $50 billion in
recapitalized securities. Mr. Radeki currently serves as a Director of
Wherehouse Entertainment, Inc., a music and video specialty retailer, and
RBX Corporation, a manufacturer of rubber and plastic foam and other
polymer products. He has previously served as Chairman of the Board of
American Rice, Inc., an international rice miller and marketer, as a member
of the Board of Directors of Service America Corporation, a national food
service management firm, Bucyrus International, Inc., a mining equipment
manufacturer, and ECO-Net, a non-profit engineering related network firm.
Mr. Radecki graduated magna cum laude in 1980 from Georgetown University
with a B.A. in Government.
Richard D. Rinehart has served as a director since April 19, 2002. Mr.
Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel
Resources, Inc. PetroCap, Inc. provides investment and merchant banking
services to a variety of clients active in the oil and gas industry.
Kestrel Resources, Inc. is a privately owned oil and gas operating company.
He served as Director of Coopers & Lybrand's Energy Systems and Services
Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to
joining Coopers & Lybrand, he was chief executive officer/founder of Dawn
Information Resources, Inc., formed in 1986 and acquired by Coopers &
Lybrand in early 1991. Mr. Rinehart served as CEO of Terrapet Energy
Corporation during the period 1982 through 1986. Prior to the formation of
Terrapet in 1982, he was employed as President of the Terrapet Division of
E.I. DuPont de Nemours and Company. Before its acquisition by DuPont, he
served as CEO and President of Terrapet Corp., a privately owned E & P
company. Before the formation of Terrapet Corp. in 1972, he was manager of
supplementary recovery methods and senior evaluation engineer with H. J.
Gruy and Associates, Inc., Dallas, Texas.
John M. White has served as a director since April 19, 2002, Mr. White is
currently an oil and gas analyst with BMO Nesbitt Burns, responsible for
Fixed Income research on oil, gas and energy companies. Prior to joining
BMO Nesbitt Burns in 1998, Mr. White was responsible for Fixed Income
research on the oil and gas industry at John S. Herold, Inc., an
independent oil and gas research and consulting firm, beginning in July
1996. Mr. White's experience also includes managing a portfolio of oil and
gas loans for The Bank of Nova Scotia, which included independent
exploration and production companies, oil service companies, gas pipelines,
gas processors and refiners from 1990 until July 1996. From 1983 to 1990,
Mr. White was with BP Exploration, where he worked primarily in exploration
and production.
Herbert C. Williamson, III has served as a director since April 19, 2002.
At present, Mr. Williamson is self-employed as a consultant. From March
2001 to March 2002 Mr. Williamson served as an investment banker with
Petrie Parkman & Co. From April 1999 to March 2001 Mr. Williamson served
as chief financial officer and from August 1999 to March 2001 as a director
of Merlon Petroleum Company, a private oil and gas company involved in
exploration and production in Egypt. Mr. Williamson served as executive
vice president, chief financial officer and director of Seven Seas
Petroleum, Inc., a publicly traded oil and gas exploration company, from
March 1998 to April 1999. From 1995 through April 1998, he served as
director in the Investment Banking Department of Credit Suisse First
Boston. Mr. Williamson served as vice chairman and executive vice
president of Parker and Parsley Petroleum Company, a publicly traded oil
and gas exploration company (now Pioneer Natural Resources Company) from
1985 through 1995.
Bill E. Coggin has served as Vice President and Chief Financial Officer
since joining the Managing General Partner in 1985. Previously, Mr. Coggin
was Controller for Rod Ric Corporation, an oil and gas drilling company,
and for C.F. Lawrence & Associates, a large independent oil and gas
operator. Mr. Coggin received a B.S. in Education and a B.A. in Accounting
from Angelo State University.
J. Steven Person has served as Vice President, Marketing since joining the
Managing General Partner in 1989. Mr. Person began in the investment
industry with Dean Witter in 1983. Prior to joining the Managing General
Partner, Mr. Person was a senior wholesaler with Capital Realty, Inc. While
at Capital Realty, he was involved in the syndication of mortgage based
securities through the major brokerage houses. Mr. Person received a
B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist
University.
Key Employees
Jon P. Tate, age 45, has served as Vice President, Land and Assistant
Secretary of the Managing General Partner since 1989. From 1981 to 1989,
Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent
oil and gas company, as land manager. Mr. Tate is a member of the Permian
Basin Landman's Association.
R. Douglas Keathley, age 47, has served as Vice President, Operations of
the Managing General Partner since 1992. Before joining us, Mr. Keathley
worked as a senior drilling engineer for ARCO Oil and Gas Company and in
similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.
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 employ any directors, executive officers or
employees. The Managing General Partner receives an administrative fee for
the management of the Partnership. The Managing General Partner received
$34,800 in 2002, 2001 and 2000, as an annual administrative fee. The
executive officers of the Managing General Partner do not receive any form
of compensation, from the Partnership; instead, their compensation is paid
solely by Southwest. The executive officers, however, may occasionally
perform administrative duties for the Partnership but receive no additional
compensation for this work.
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.
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. 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 2002, the Managing General Partner received $34,800 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 $55,400 for administrative overhead
attributable to operating such properties during 2002.
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 $2,800 for the year ended
December 31, 2002.
The terms of the above transactions are similar to ones, which would have
been obtained through arm's length negotiations with unaffiliated third
parties.
Item 14. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures. The chief executive
officer and chief financial officer of the Partnership's managing general
partner have evaluated the effectiveness of the design and operation of the
Partnership's disclosure controls and procedures (as defined in Exchange
Act Rule 13a-14(c)) as of a date within 90 days of the filing date of this
annual report. Based on that evaluation, the chief executive officer and
chief financial officer have concluded that the Partnership's disclosure
controls and procedures are effective to ensure that material information
relating to the Partnership is made known to such officers by others within
these entities, particularly during the period this annual report was
prepared, in order to allow timely decisions regarding required disclosure.
(b) Changes in Internal Controls. There have not been any significant
changes in the Partnership's internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation.
Part IV
Item 15. 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-B, L.P., dated August 24, 1993.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1993).
(b) Agreement of Limited
Partnership of Southwest Royalties Institutional
Income Fund XI-B, L.P., dated August 27, 1993.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1993).
18.1 Letter re Change in Accounting Principles
99.1 Certification pursuant to 18 U.S.C. Section 1350
99.2 Certification pursuant to 18 U.S.C. Section 1350
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2002.
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-B, 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: November 10, 2003
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below hereby constitutes and appoints H.H. Wommack, III and Bill E. Coggin,
and each of them severally, his true and lawful attorney-in-fact and agent,
with full power of substitution and resubstitution, for him and in his
name, place and stead, in any and all capacities, to sign any and all
amendment to this Report, and to file the same, with all exhibits thereto,
and other documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorney-in-fact and agent full
power and authority to do and perform each and every act and thing
requisite and necessary to be done as fully to all intents and purposes as
he might or could do in person, hereby ratifying and confirming that all
that said attorney-in-fact and agent, or his substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed below by
the following persons on behalf of the Registrant and in the capacities and
on the dates indicated.
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.
/s/ H. H. Wommack, III /s/ Bill E. Coggin
- --------------------------- ------------------------
- -------------------- -----------------------
H. H. Wommack, III, Bill E. Coggin,
Chairman of the Board, Executive Vice President
President, Director and and Chief Financial
Chief Executive Officer Officer
Date: November 6, 2003 Date: November 6,
2003
/s/ William P. Nicoletti /s/ James N. Chapman
- --------------------------- ------------------------
- -------------------- -----------------------
William P. Nicoletti, James N. Chapman,
Director Director
Date: November 10, 2003 Date: November 6,
2003
/s/ Richard D. Rinehart /s/ Joseph J. Radecki,
Jr.
- --------------------------- ------------------------
- -------------------- -----------------------
Richard D. Rinehart, Joseph J. Radecki, Jr.,
Director Director
Date: November 7, 2003 Date: November 4,
2003
/s/ Herbert C. Williamson,
III
- --------------------------- ------------------------
- -------------------- -----------------------
Herbert C. Williamson, III, John M. White, Director
Director
Date: November 7, 2003 Date:
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this annual report on Form 10-K/A of
Southwest Royalties Institutional Income Fund XI-B, L.P.;
2. Based on my knowledge, this annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: November 10, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund XI-B, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this annual report on Form 10-K/A of
Southwest Royalties Institutional Income Fund XI-B, L.P.;
2. Based on my knowledge, this annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: November 10, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund XI-B, L.P.
Exhibit Index
Item No. Description Page
No.
Exhibit 18.1 Letter re Change in Accounting
Principles 48
Exhibit 99.1 Certification pursuant to 18 U.S.C.
49
Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Exhibit 99.2 Certification pursuant to 18 U.S.C.
50
Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
EXHIBIT 18.1
June 4, 2003
Southwest Royalties, Inc. (As Managing General Partner of the
Partnerships)
Midland, Texas
Ladies and Gentlemen:
We have audited the balance sheets of the Southwest Royalties,
Inc. public partnerships (see attached listing) (the
"Partnerships") as of December 31, 2002 and 2001, and the related
statements of operations, statements of changes in partners'
equity, and cash flows for each of the years in the three-year
period ended December 31, 2002, and have reported thereon under
date of March 14, 2003. The aforementioned financial statements
and our audit report thereon are included in each of the
individual Partnership's annual reports on Form 10-K/A for the
year ended December 31, 2002.
As stated in Note 2 to those financial statements, the
Partnerships changed their method of accounting for amortization
of capitalized costs from the units-of-revenue method to the
units-of-production method, and that the newly adopted accounting
principle is preferable in the circumstances because the units-of-
production method results in a better matching of the costs of
oil and gas production against the related revenue received in
periods of volatile prices for production as have been
experienced in recent periods. Additionally, the units-of-
production method is the predominant method used by full cost
companies in the oil and gas industry, accordingly, the change
improves the comparability of the Partnerships' financial
statements with its peer group. In accordance with your request,
we have reviewed and discussed with Partnership officials the
circumstances and business judgment and planning upon which the
decision to make this change in the method of accounting was
based.
With regard to the aforementioned accounting change,
authoritative criteria have not been established for evaluating
the preferability of one acceptable method of accounting over
another acceptable method. However, for purposes of the
Partnership's compliance with the requirements of the Securities
and Exchange Commission, we are furnishing this letter.
Based on our review and discussion, with reliance on management's
business judgment and planning, we concur that the newly adopted
method of accounting is preferable in the Partnerships'
circumstances.
Very truly yours,
KPMG LLP
CERTIFICATION PURSUANT TO
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Royalties
Institutional Income Fund XI-B, Limited Partnership (the
"Company") on Form 10-K/A for the period ending December 31, 2002
as filed with the Securities and Exchange Commission on the date
hereof (the "Report"), I, H.H. Wommack, III, Chief Executive
Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the
Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and results of
operation of the Company.
Date: November 10, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund XI-B, L.P.
CERTIFICATION PURSUANT TO
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Royalties
Institutional Income Fund XI-B, Limited Partnership (the
"Company") on Form 10-K/A for the period ending December 31, 2002
as filed with the Securities and Exchange Commission on the date
hereof (the "Report"), I, Bill E. Coggin, Chief Financial Officer
of the Managing General Partner of the Company, certify, pursuant
to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(3) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(4) The information contained in the Report fairly presents, in
all material respects, the financial condition and results of
operation of the Company.
Date: November 10, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund XI-B, L.P.