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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2003
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 33-38511
Southwest Developmental Drilling Fund 91-A, L.P.
Exact name of registrant as specified in
its limited partnership agreement
Delaware 75-2387814
(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 and general partner interests
Indicate by check mark whether registrant (1) has filed reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K 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]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No 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 45. The exhibit
index is found on page 42.
Table of Contents
Item Page
Part I
Glossary of Oil and Gas Terms 3
1. Business 5
2. Properties 9
3. Legal Proceedings 10
4. Submission of Matters to a Vote of Security Holders 10
Part II
5. Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities 11
6. Selected Financial Data 12
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 13
7A. Quantitative and Qualitative Disclosures About Market Risk 19
8. Financial Statements and Supplementary Data 20
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 34
9A. Controls and Procedures 34
Part III
10. Directors and Executive Officers of the Registrant 35
11. Executive Compensation 37
12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters 37
13. Certain Relationships and Related Transactions 38
14. Principal Accountant Fees and Services 38
Part IV
15. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 39
Signatures 40
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.
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 Developmental Drilling Fund 91-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on January 7,
1991. The offering of limited and general partner interests began
September 17, 1991 as part of a shelf offering registered under the name
Southwest Developmental Drilling Program 1991-92, reached minimum capital
requirements on April 22, 1992 and concluded April 30, 1992. The
Partnership has no subsidiaries.
The Partnership has expended its capital and acquired leasehold interests
and completed drilling operations. The Partnership has produced and
marketed the crude oil and natural gas produced from such properties.
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 81 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. The
Partnership has no employees.
Introductory Note - Statement of Financial Accounting Standard No. 143
The Partnership implemented SFAS No. 143 effective January 1, 2003 (See
Note 3 to the Partnership's financial statements).
Introductory Note - Depletion Method
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 4 to the Partnership's financial statements. This change
in depletion method was applied as a cumulative effect of a change in
accounting principle effective as of January 1, 2002.
Principal Products, Marketing and Distribution
The Partnership has acquired leasehold interests and drilled oil and gas
properties located in Texas and New Mexico. All activities of the
Partnership are confined to the continental United States. All oil and gas
produced from these properties is sold to unrelated third parties in the
oil and gas business.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. The prices received by
the Partnership for its oil and gas production depend upon numerous factors
beyond the Partnership's control, including competition, economic,
political and regulatory developments and competitive energy sources, and
make it particularly difficult to estimate future prices of oil and natural
gas.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
---- ----
2003 84% 16%
2002 90% 10%
2001 82% 18%
As the table indicates, the majority of the Partnership's revenue is from
its oil production; therefore, Partnership revenues will be highly
dependent upon the future prices and demands for oil.
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
97% of the Partnership's total oil and gas production during 2003: Plains
Marketing LP for 80% and Duke Energy Field Services LP for 17%. Contracts
for 2003 with these major purchasers cover time periods ranging from month
to month contracts up to year-to-year contract periods. Prices received
from these major purchasers ranged from $4.64 per mcf and $30.08 per
barrel. One purchaser accounted for 85% of the Partnership's total oil and
gas production during 2002: Plains Marketing LP for 85%. Contracts for
2002 with these major purchaser covers month-to-month contracts. Prices
received from this major purchaser were $23.36 per barrel. Two purchasers
accounted for 94% of the Partnership's total oil and gas production during
2001: Plains Marketing LP for 76% and Duke Energy Field Services for 18%.
Contracts for 2001 with these major purchasers cover time periods ranging
from month to month contracts up to year-to-year contract periods. Prices
received from these major purchasers ranged from $4.51 per mcf and $27.05
per barrel. All purchasers of the Partnership's oil and gas production are
unrelated third parties. In the event this purchaser 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 total 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 or drilling
operations, 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, land men 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,
2003 there were 81 individuals directly employed by the Managing General
Partner in various capacities.
Item 2. Properties
In determining whether an interest in a particular property was to be
acquired, the Managing General Partner considered such criteria as
estimated oil and gas reserves, estimated drilling costs, 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, 2003, the Partnership possessed an interest in oil and
gas properties located in Eddy County of New Mexico and Rains, Van Zandt
and Ward County of Texas. These properties consist of various interests in
3 wells.
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 2003, 2002 and 2001.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and and Interest Wells Oil Gas
Location (bbls) (mcf)
- ------------- ------------ ----- -------- --------
- ---- -- -
Carson F #1 6/92 1 16,000 20,000
Ward County, 89% 1 16,000(1 20,000(1
) )
Texas working
interest
Carson E 6/92 at 1 14,000 8,000
Ward County, 90% working 1 14,000(1 8,000(1)
Texas )
interest
(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, 2004. 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, 2004 are an average price of $31.81 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, 2004 are an
average price of $5.49 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 2003.
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. All of the proved
reserves are included in the engineering reports, which evaluate the
Partnership's present reserves.
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 Operations.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth
quarter of 2003 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
Market Information
Investor partner interests, or units, in the Partnership were initially
offered and sold for a price of $1,000. Investor 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 or
general partner without the consent of the Managing General Partner.
Each Additional General Partner interest, whom elected at the time of
subscription into the Partnership, has been converted into a limited
partner effective January 1, 1994.
The Managing General Partner has the right, but not the obligation in
accordance with the partnership agreement, 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.
Issuer Purchases of Equity Securities
Maximum
Total Number (or
Number
of Units Approximat
e
Purchased Value) of
as Units
Part of that May
Publicly Yet Be
Total Announced Purchased
Number
of Units Average Plans or Under the
Price Plans
Period(1) Purchased Paid Per Programs or
Unit Programs
October 1-
31,
2003 - $ - - N/A
November 1-
30,
2003 - - - N/A
December 1-
31,
2003 - - - N/A
TOTALS - $ -
(1) In April 2003, the Managing General Partner purchased a total of 50
limited partner units from limited partners at an average base price of
$135.68 per unit. As of December 31, 2002, no limited partner units were
purchased by the Managing General Partner. In 2001, 17 limited partner
units were tendered to and purchased by the Managing General Partner at an
average base price of $214.15 per unit. These discretionary repurchases
were made based upon the partnership agreement criteria.
Number of Limited and General Partner Interest Holders
As of December 31, 2003, there were 101 holders of limited partner units
and no holders of general partner units in the Partnership.
Distributions
Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and
Agreement of Limited Partnership, "Net Cash Flow" is distributed to the
partners on a quarterly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's drilling activities, less (i) General and
Administrative Costs, (ii) Operating Costs, and (iii) any reserves
necessary to meet current and anticipated needs of the Partnership,
including, but not limited to drilling cost overruns, as determined in the
sole discretion of the Managing General Partner."
During 2003, distributions were made totaling $32,765, with $29,161
distributed to the investor partners and $3,604 to the Managing General
Partner. For the year ended December 31, 2003, distributions of $25.48 per
investor partner unit were made, based upon 1,144.50 investor partner units
outstanding. During 2002, distributions were made totaling $18,462, with
$16,431 distributed to the investor partners and $2,031 to the Managing
General Partner. For the year ended December 31, 2002, distributions of
$14.36 per investor partner unit were made, based upon 1,144.50 investor
partner units outstanding. During 2001, distributions were made totaling
$62,234, with $55,388 distributed to the investor partners and $6,846 to
the Managing General Partner. For the year ended December 31, 2001,
distributions of $48.39 per investor partner unit were made, based upon
1,144.50 investor partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2003, 2002, 2001, 2000 and 1999 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
------------------------------------------------
-----
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Revenues $ 161,802 105,095 139,286 162,884 252,026
Net income before
cumulative
effects of 23,093 2,942 30,325 58,242 119,990
accounting
changes
Net income 33,297 102,942 30,325 58,242 119,990
Partners' share
of
net income
(loss):
Managing General
Partner 6,767 3,184 5,536 7,617 17,159
Investor partners 26,530 99,758 24,789 50,625 102,831
Investor
partners'
net income
(loss) per unit
before
cumulative
effects
of accounting 15.25
changes (.21) 21.66 44.23 89.85
Investor
partners'
net income 23.18
(loss) per unit 87.16 21.66 44.23 89.85
Investor
partners'
cash
distributions
per unit 25.48
14.36 48.39 94.12 66.10
Total assets $ 235,779 217,697 133,225 165,095 237,888
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 91-A, L.P. was organized as a
Delaware limited partnership on January 7, 1991. The offering of limited
and general partner interests began on September 17, 1991 as part of a
shelf offering registered under the name Southwest Developmental Drilling
Program 1991-92. Minimum capital requirements for the Partnership were met
on April 22, 1992, with the offering of limited and general partner
interests concluding on April 30, 1992, with total investor partner
contributions of $1,144,500. The Managing General Partner made a
contribution to the capital of the Partnership at the conclusion of its
offering period in an amount equal to 1% of its net capital contributions.
The Managing General Partner contribution was $9,800. Total capital
contributions were $1,154,300.
The Partnership was formed to engage primarily in the business of drilling
developmental and exploratory wells, to produce and market crude oil and
natural gas produced from such properties, to distribute any net proceeds
from operations to the general and limited partners and to the extent
necessary, acquire leases, which contain drilling prospects. Net revenues
will not be reinvested in other revenue producing assets except to the
extent that performance of remedial work is needed to improve a well's
producing capabilities. The economic life of the Partnership thus depends
on the period over which the Partnership's oil and gas reserves are
economically recoverable.
Based on current conditions, management anticipates performing no workovers
during 2004 to enhance production. The partnership will most likely
continue to experience sporadic production. Accordingly, if commodity
prices remain unchanged, the Partnership expects future earnings to decline
due to anticipated production declines.
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 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.
A. General Comparison of the Years Ended December 31, 2003 and 2002
The following table provides certain information regarding performance
factors for the years ended December 31, 2003 and 2002:
Year Ended Percenta
ge
December 31, Increase
2003 2002 (Decreas
e)
---- ---- --------
-
Average price per $ 30.29 21%
barrel of oil 24.96
Average price per mcf $ 4.73 67%
of gas 2.83
Oil production in 4,400 3,750 17%
barrels
Gas production in mcf 5,300 3,700 43%
Oil and gas revenue $ 158,356 104,083 52%
Production expense $ 86,296 59,781 44%
Partnership $ 32,765 18,462 77%
distributions
Investor partner $ 29,161 16,431 77%
distributions
Per unit distribution $ 25.48 77%
to investor partners 14.36
Number of investor 1,144.5
partner units 1,144.5
Revenues
The Partnership's oil and gas revenues increased to $158,356 from $104,083
for the years ended December 31, 2003 and 2002, respectively, an increase
of 52%. The principal factors affecting the comparison of the years ended
December 31, 2003 and 2002 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the year ended December 31, 2003 as compared to the
year ended December 31, 2002 by 21%, or $5.33 per barrel, resulting in
an increase of approximately $23,500 in revenues. Oil sales represented
84% of total oil and gas sales during the year ended December 31, 2003
as compared to 90% during the year ended December 31, 2002.
The average price for an mcf of gas received by the Partnership
increased during the same period by 67%, or $1.90 per mcf, resulting in
an increase of approximately $10,100 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $33,600. 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 increased approximately 650 barrels or 17% during the
year ended December 31, 2003 as compared to the year ended December 31,
2002, resulting in an increase of approximately $16,200 in revenues.
Gas production increased approximately 1,600 mcf or 43% during the same
period, resulting in an increase of approximately $4,500 in revenues.
The total increase in revenues due to the change in production is
approximately $20,700. The increase in oil and gas volumes are the
result of one well returning to historic production levels after being
down in 2002.
Costs and Expenses
Total costs and expenses increased to $138,079 from $102,153 for the years
ended December 31, 2003 and 2002, respectively, an increase of 30%. The
increase is the result of the addition of accretion expense, higher general
and administrative costs, lease operating costs and depletion expense.
1. Lease operating costs and production taxes were 44% higher, or
approximately $26,500 more during the year ended December 31, 2003 as
compared to the year ended December 31, 2002. The increase in lease
operating costs is the result of well repairs on one well and the increase
in production taxes due to the increase in commodity prices.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased
40% or approximately $6,500 during the year ended December 31, 2003 as
compared to the year ended December 31, 2002.
3. Depletion expense increased to $28,221 for the year ended December 31,
2003 from $26,000 for the same period in 2002. This represents an
increase of 9%. The contributing factor to the decrease in depletion
expense is in relation to the BOE depletion rate for the year ended
December 31, 2003, which was $5.34 applied to 5,283 BOE as compared to
$5.95 applied to 4,367 BOE for the same period in 2002.
Cumulative effect of change in accounting principle - SFAS No. 143
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement Obligations
("SFAS No. 143"). Adoption of SFAS No. 143 is required for all companies
with fiscal years beginning after June 15, 2002. 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 depreciate the
additional cost over the estimated useful life of the asset. On January 1,
2003, the Partnership recorded additional costs, net of accumulated
depreciation, of approximately $26,483, a long term liability of
approximately $16,279 and a gain of approximately $10,204 for the
cumulative effect on depreciation of the additional costs and accretion
expense on the liability related to expected abandonment costs of its oil
and natural gas producing properties. At December 31, 2003, the asset
retirement obligation was $17,581, and the increase in the balance from
January 1, 2003 of $1,302 is due to accretion expense. The pro forma
amounts of the asset retirement obligation as of December 31, 2002, 2001
and 2000, were approximately $16,279, $15,081 and $13,971, respectively.
The pro forma amounts of the asset retirement obligation were measured
using information, assumptions and interest rates as of the adoption date
of January 1, 2003.
B. 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 $ 24.96 (3%)
barrel of oil 25.84
Average price per mcf $ 2.83 (36%)
of gas 4.41
Oil production in 3,750 4,440 (16%)
barrels
Gas production in mcf 3,700 5,540 (33%)
Oil and gas revenue $ 104,083 139,132 (25%)
Production expense $ 59,781 73,616 (19%)
Partnership $ 18,462 62,234 (70%)
distributions
Investor partner $ 16,431 55,388 (70%)
distributions
Per unit distribution $ 14.36 (70%)
to investor partners 48.39
Number of investor 1,144.5
partner units 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $104,083 from $139,132
for the years ended December 31, 2002 and 2001, respectively, a decrease of
25%. 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 3%, or $.88 per barrel, resulting in a
decrease of approximately $3,300 in revenues. Oil sales represented 90%
of total oil and gas sales during the year ended December 31, 2002 as
compared to 82% 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 36%, or $1.58 per mcf, resulting in
a decrease of approximately $5,800 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $9,100. The market price
for oil and gas has been extremely volatile over the past decade and
management expects a certain amount of volatility to continue in the
foreseeable future.
2. Oil production decreased approximately 690 barrels or 16% during the
year ended December 31, 2002 as compared to the year ended December 31,
2001, resulting in a decrease of approximately $17,800 in revenues.
Gas production decreased approximately 1,840 mcf or 33% during the same
period, resulting in a decrease of approximately $8,100 in revenues.
The total decrease in revenues due to the change in production is
approximately $25,900. The decrease in oil production is due to
fluctuation in production on one out of three leases. The decrease in
gas production is due primarily to downtime on one lease, which is
water production influenced and gas production cannot be restored, in
addition one lease experiences fluctuations in levels of production.
Costs and Expenses
Total costs and expenses decreased to $102,153 from $108,961 for the years
ended December 31, 2002 and 2001, respectively, a decrease of 6%. The
decrease is the result of lower depletion expense and lease operating
costs, partially offset an increase in general and administrative costs.
2. Lease operating costs and production taxes were 19% lower, or
approximately $13,800 less during the year ended December 31, 2002 as
compared to the year ended December 31, 2001. The decrease in lease
operating expense is due mainly to repairs and maintenance performed during
2001.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 7%
or approximately $1,000 during the year ended December 31, 2002 as
compared to the year ended December 31, 2001.
3. Depletion expense increased to $26,000 for the year ended December 31,
2002 from $20,000 for the same period in 2001. This represents an
increase of 30%. 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
$13,000 and increase 2002 net income by $87,000. See Note 4 of the
notes to the Partnership's financial statements.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2003, 2002 and 2001
was $33,297, $102,942 and $30,325, respectively. Partnership distributions
for the years ended December 31, 2003, 2002 and 2001 were $32,765, $18,462
and $62,234, respectively.
The sources for the 2003 distributions of $32,765 were oil and gas
operations of approximately $40,700 and the change in oil and gas
properties of approximately $(200), resulting in excess cash for
contingencies or subsequent distributions. The sources for the 2002
distributions of $18,462 were oil and gas operations of approximately
$26,900 and the change in oil and gas properties of approximately $(9,100),
with the balance from available cash on hand at the beginning of the
period. The sources for the 2001 distributions of $62,234 were oil and gas
operations of approximately $60,400 and the change in oil and gas
properties of approximately $(200), with the balance from available cash on
hand at the beginning of the period.
Total distributions during the year ended December 31, 2003 were $32,765 of
which $29,161 was distributed to the investor partners and $3,604 to the
Managing General Partner. The per unit distribution to investor partners
during the same period was $25.48. Total distributions during the year
ended December 31, 2002 were $18,462 of which $16,431 was distributed to
the investor partners and $2,031 to the Managing General Partner. The per
unit distribution to investor partners during the same period was $14.36.
Total distributions during the year ended December 31, 2001 were $62,234 of
which $55,388 was distributed to the investor partners and $6,846 to the
Managing General Partner. The per unit distribution to investor partners
during the same period was $48.39.
Cumulative cash distributions of $1,447,236 have been made to the general
and limited partners as of December 31, 2003. As of December 31, 2003,
$1,289,951 or $1,127.09 per investor partner unit, has been distributed to
the investor partners, representing a 100% return of capital and a 13%
return on capital contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
oil and gas properties. The Partnership anticipates the primary source of
cash to continue being from the oil and gas operations.
Cash flows provided by operating activities were approximately $40,700 in
2003 compared to $26,900 in 2002 and approximately $60,400 in 2001.
Cash flows used in investing activities were approximately $200 in 2003
compared to $9,100 in 2002 and approximately $200 in 2001. The principal
use of the 2003 cash flow from investing activities was additions to oil
and gas properties.
Cash flows used in financing activities were approximately $32,800 in 2003
compared to $18,500 in 2002 and approximately $62,200 in 2001. The only
use in the 2003 financing activities was the distributions to partners.
As of December 31, 2003, the Partnership had approximately $35,500 in
working capital. The Managing General Partner knows of no unusual
contractual 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.
Liquidity - Managing General Partner
As of December 31, 2003, the Managing General Partner is in violation of
several covenants pertaining to their Amended and Restated Revolving Credit
Agreement due June 1, 2006 and their Senior Second Lien Secured Credit
Agreement due October 15, 2008. Due to the covenant violations, the
Managing General Partner is in default under their Amended and Restated
Revolving Credit Agreement and the Senior Second Lien Secured Credit
Agreement, and all amounts due under these agreements have been classified
as a current liability on the Managing General Partner's balance sheet at
December 31, 2003. The significant working capital deficit and debt being
in default at December 31, 2003, raise substantial doubt about the Managing
General Partner's ability to continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the Managing
General Partner announced its decision to explore a merger, sale of the
stock or other transaction involving the Managing General Partner. The
Board has formed a Special Committee of independent directors to oversee
the sales process. The Special Committee has retained independent
financial and legal advisors to work closely with the management of the
Managing General Partner to implement the sales process. There can be no
assurance that a sale of the Managing General Partner will be consummated
or what terms, if consummated, the sale will be on.
Recent Accounting Pronouncements
The EITF is considering two issues related to the reporting of oil and gas
mineral rights. Issue No. 03-O, "Whether Mineral Rights Are Tangible or
Intangible Assets," is whether or not mineral rights are intangible assets
pursuant to SFAS No. 141, "Business Combinations." Issue No. 03-S,
"Application of SFAS No. 142, Goodwill and Other Intangible Assets, to Oil
and Gas Companies," is, if oil and gas drilling rights are intangible
assets, whether those assets are subject to the classification and
disclosure provisions of SFAS No. 142. The Partnership classifies the cost
of oil and gas mineral rights as properties and equipment and believes that
this is consistent with oil and gas accounting and industry practice. The
disclosures required by SFAS Nos. 141 and 142 would be made in the notes to
the financial statements. There would be no effect on the statement of
income or cash flows as the intangible assets related to oil and gas
mineral rights would continue to be amortized under the full cost method of
accounting.
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 21
Balance Sheets 22
Statements of Operations 23
Statement of Changes in Partners' Equity 24
Statements of Cash Flows 25
Notes to Financial Statements 26
INDEPENDENT AUDITORS' REPORT
The Partners
Southwest Developmental Drilling
Fund 91-A, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Developmental
Drilling Fund 91-A, L.P. (the "Partnership") as of December 31, 2003 and
2002, 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, 2003. 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 Developmental
Drilling Fund 91-A, L.P. as of December 31, 2003 and 2002 and the results
of its operations and its cash flows for each of the years in the three
year period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 4 to the financial statements, the Partnership changed
its method of computing depletion in 2002. Also, as discussed in Note 3 to
the financial statements, the Partnership changed its method of accounting
for asset retirement obligations as of January 1, 2003.
KPMG LLP
Midland, Texas
March 19, 2004, except as to Note 9, which is as of May 3, 2004
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2003 and 2002
2003 2002
---- ----
Assets
- ----------
Current assets:
Cash and cash equivalents $ 19,513 11,779
Receivable from Managing 15,974 4,069
General Partner
-------- --------
---- ----
Total current assets 35,487 15,848
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 1,115,29 1,107,84
0 9
Less accumulated
depreciation,
depletion and 914,998 906,000
amortization
-------- --------
---- ----
Net oil and gas 200,292 201,849
properties
-------- --------
---- ----
$ 235,779 217,697
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability:
Distribution payable $ - 31
-------- --------
---- ----
Asset retirement obligation 17,581 -
-------- --------
---- ----
Partners' equity:
Managing General Partner 26,829 23,666
Investor partners 191,369 194,000
-------- --------
---- ----
Total partners' equity 218,198 217,666
-------- --------
---- ----
$ 235,779 217,697
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statements of Operations
For the years ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
Revenues
- -------------
Oil and gas sales $ 158,356 104,083 139,132
Interest income from operations - 9 154
Other 3,446 1,003 -
-------- -------- --------
-- -- --
161,802 105,095 139,286
-------- -------- --------
-- -- --
Expenses
- -------------
Production 86,296 59,781 73,616
General and administrative 22,890 16,372 15,345
Accretion of asset retirement 1,302 - -
obligation
Depreciation, depletion and 28,221 26,000 20,000
amortization
-------- -------- --------
-- -- --
138,709 102,153 108,961
-------- -------- --------
-- -- --
Net income before cumulative
effects
of accounting changes 23,093 2,942 30,325
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See 10,204 - -
Note 3
Cumulative effect of change in
accounting principle
- change in depletion method - - 100,000 -
See Note 4
-------- -------- --------
-- -- --
Net income $ 33,297 102,942 30,325
====== ====== ======
Net income allocated to:
Managing General Partner $ 6,767 3,184 5,536
====== ====== ======
Investor partners $ 26,530 99,758 24,789
====== ====== ======
Per investor partner unit $ 15.25 (.21) 21.66
before cumulative effect
Cumulative effects per investor 7.93 87.37 -
partner unit
-------- -------- --------
-- -- --
Per investor partner unit $ 23.18 87.16 21.66
====== ====== ======
Pro forma amounts assuming
changes are applied
retroactively (See Notes 3 and 4
for details):
Net income before cumulative $ - 1,744 13,215
effect
====== ====== ======
Per investor partner unit $ - (1.14) 6.82
(1,144.5 units)
====== ====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
For the years ended December 31, 2003, 2002 and 2001
Managing
General Investor
Partner Partners Total
------- -------- -----
Balance at December 31, $ 23,823 141,272 165,095
2000
Net income 5,536 24,789 30,325
Distributions (6,846) (55,388) (62,234)
-------- -------- --------
-- --- ----
Balance at December 31, 22,513 110,673 133,186
2001
Net income 3,184 99,758 102,942
Distributions (2,031) (16,431) (18,462)
-------- -------- --------
-- --- ----
Balance at December 31, 23,666 194,000 217,666
2002
Net income 6,767 26,530 33,297
Distributions (3,604) (29,161) (32,765)
-------- -------- --------
-- --- ----
Balance at December 31, $ 26,829 191,369 218,198
2003
====== ====== =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
For the years ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
Cash flows from operating
activities:
Cash received from oil and $ 148,024 101,165 152,656
gas sales
Cash paid to Managing General
Partner
for administrative fees and
general
and administrative overhead (110,759 (75,257) (92,367)
)
Interest received - 9 154
Miscellaneous settlement 3,446 1,003 -
-------- -------- --------
---- ---- ----
Net cash provided by 40,711 26,920 60,443
operating activities
-------- -------- --------
---- ---- ----
Cash flows used in investing
activities:
Additions to oil and gas (181) (9,073) (184)
properties
-------- -------- --------
---- ---- ----
Cash flows used in financing
activities:
Distributions to partners (32,796) (18,470) (62,195)
-------- -------- --------
---- ---- ----
Net increase (decrease) in
cash and cash
equivalents 7,734 (623) (1,936)
Beginning of period 11,779 12,402 14,338
-------- -------- --------
---- ---- ----
End of period $ 19,513 11,779 12,402
======= ======= =======
Reconciliation of net income
to net
cash provided by operating
activities:
Net income $ 33,297 102,942 30,325
Adjustments to reconcile net
income to
net cash provided by
operating activities:
Accretion of asset retirement 1,302 - -
obligation
Depreciation, depletion and 28,221 26,000 20,000
amortization
Cumulative effect of change (10,204) (100,000 -
in accounting principle )
(Increase) decrease in (10,332) (2,918) 13,524
receivables
(Decrease) increase in (1,573) 896 (3,406)
payables
-------- -------- --------
---- ---- ----
Net cash provided by operating $ 40,711 26,920 60,443
activities
======= ======= =======
Noncash investing and
financing activities:
Increase in oil and gas
properties - Adoption
of SFAS No. 143 $ 26,483 - -
======= ======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 91-A, L.P. was organized under
the laws of the state of Delaware on January 7, 1991 for the purpose
of drilling developmental and exploratory wells 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 sells 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. Revenues, costs and
expenses are allocated as follows:
Managing
General Investor
Partner Partners
-------- --------
Interest income on capital - 100%
contributions
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and offering - 100%
costs (1)
Syndication costs - 100%
Amortization of organization - 100%
costs
Lease acquisition costs 1% 99%
Gain/loss on property 11% 89%
disposition*
Operating and administrative 11% 89%
costs*(2)
Depreciation, depletion and
amortization
of oil and gas properties - 100%
Intangible drilling and - 100%
development costs
All other costs* 11% 89%
*After the Investor Partners have received distributions totaling 150%
of their capital contributions, the allocation will change to 15%
Managing General Partner and 85% Investor Partners.
(1) All organization costs in excess of 4% of initial capital
contributions will be paid by the Managing General Partner and
will be treated as a capital contribution. The Partnership paid
the Managing General Partner an amount equal to 4% of initial
capital contributions for such organization costs.
(2) Administrative costs in any year, which exceed 2% of capital
contributions shall be paid by the Managing General Partner and
will be treated as a capital contribution.
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 year ended December 31, 2001, 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, 2003, 2002 and 2001 the net capitalized costs did not exceed the
estimated present value of oil and gas reserves.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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, 2003 and 2002,
there were no significant amounts of imbalance in terms of units or
value.
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," the
Partnership's tax basis in its net oil and gas properties at December
31, 2003 and 2002 is $197,039 and $197,013, respectively, less than
that shown on the accompanying Balance Sheets 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 Investor Partner Units
As of December 31, 2003, 2002 and 2001, there were 1,144.5 investor
partner units outstanding held by 101, 102 and 102 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.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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 EITF is considering two issues related to the reporting of oil and
gas mineral rights. Issue No. 03-O, "Whether Mineral Rights Are
Tangible or Intangible Assets," is whether or not mineral rights are
intangible assets pursuant to SFAS No. 141, "Business Combinations."
Issue No. 03-S, "Application of SFAS No. 142, Goodwill and Other
Intangible Assets, to Oil and Gas Companies," is, if oil and gas
drilling rights are intangible assets, whether those assets are
subject to the classification and disclosure provisions of SFAS No.
142. The Partnership classifies the cost of oil and gas mineral
rights as properties and equipment and believes that this is
consistent with oil and gas accounting and industry practice. The
disclosures required by SFAS Nos. 141 and 142 would be made in the
notes to the financial statements. There would be no effect on the
statement of income or cash flows as the intangible assets related to
oil and gas mineral rights would continue to be amortized under the
full cost method of accounting.
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 4)
3. Cumulative effect of change in accounting principle - SFAS No. 143
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required
for all companies with fiscal years beginning after June 15, 2002.
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 depreciate the additional cost over
the estimated useful life of the asset. On January 1, 2003, the
Partnership recorded additional costs, net of accumulated depreciation
of approximately $26,483, a long term liability of approximately
$16,279 and a gain of approximately $10,204 for the cumulative effect
on depreciation of the additional costs and accretion expense on the
liability related to expected abandonment costs of its oil and natural
gas producing properties. At December 31, 2003, the asset retirement
obligation was $17,581, and the increase in the balance from January
1, 2003 of $1,302 is due to accretion expense. The pro forma amounts
of the asset retirement obligation as of December 31, 2002, 2001 and
2000, were approximately $16,279, $15,081 and $13,971, respectively.
The pro forma amounts of the asset retirement obligation were measured
using information, assumptions and interest rates as of the adoption
date of January 1, 2003. The pro forma amounts for the years ended
December 31, 2002 and 2001, which are presented below, reflect the
effect of retroactive application of SFAS No. 143.
2002 2001
-------- -------
------
Pro forma amounts assuming
change is applied
retroactively:
Net income before cumulative
effect
for change in depletion $ 1,744 29,215
method
====== ======
Per limited partner unit $ (1.14) 20.80
(1,144.5 units)
====== ======
Net income $ 101,744 29,215
====== ======
Per limited partner unit $ 86.23 20.80
(1,144.5 units)
====== ======
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Cumulative effect of a change in accounting principle - change in
depletion method
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 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 $100,000 effective as of January
1, 2002. The Partnership's depletion for the years ended 2003 and
2002 have been calculated using the units-of-production method and
2001 has not been restated. The pro forma amounts for 2001, which are
presented below, reflect the effect of retroactive application of the
units-of-production method. See Note 11 for the effects of the change
in depletion method on the individual quarters of 2002.
2001
-------
Pro forma amounts assuming
change is applied
retroactively:
Net income $ 14,325
======
Per limited partner unit $ 7.68
(1,144.5 units)
======
5. Liquidity - Managing General Partner
As of December 31, 2003, the Managing General Partner is in violation
of several covenants pertaining to their Amended and Restated
Revolving Credit Agreement due June 1, 2006 and their Senior Second
Lien Secured Credit Agreement due October 15, 2008. Due to the
covenant violations, the Managing General Partner is in default under
their Amended and Restated Revolving Credit Agreement and the Senior
Second Lien Secured Credit Agreement, and all amounts due under these
agreements have been classified as a current liability on the Managing
General Partner's balance sheet at December 31, 2003. The significant
working capital deficit and debt being in default at December 31,
2003, raise substantial doubt about the Managing General Partner's
ability to continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the
Managing General Partner announced its decision to explore a merger,
sale of the stock or other transaction involving the Managing General
Partner. The Board has formed a Special Committee of independent
directors to oversee the sales process. The Special Committee has
retained independent financial and legal advisors to work closely with
the management of the Managing General Partner to implement the sales
process. There can be no assurance that a sale of the Managing
General Partner will be consummated or what terms, if consummated, the
sale will be on.
6. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
shall be further reduced by a risk factor discount of no more than one-
third (1/3) to be determined by the Managing General Partner in its
sole and absolute discretion.
The Partnership is subject to various federal, state and local
environmental laws and regulations, which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Commitments and Contingent Liabilities - continued
As of December 31, 2003, 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.
7. 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 $12,000,
$12,100 and $11,800 for the years ended December 31, 2003, 2002 and
2001, respectively. In addition, the Managing General Partner and
certain officers and employees may have an interest in some of the
properties that the Partnership also participates.
Southwest Royalties, Inc., the Managing General Partner, was paid
$9,400 in 2003, 2002 and 2001 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 $16,000 and $4,100 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2003 and 2002, respectively.
8. 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 97% of the Partnership's total oil and gas
production during 2003: Plains Marketing LP for 80% and Duke Energy
Field Services LP for 17%. One purchaser accounted for 85% of the
Partnership's total oil and gas production during 2002: Plains
Marketing LP for 85%. Two purchasers accounted for 94% of the
Partnership's total oil and gas production during 2001: Plains
Marketing LP for 76% and Duke Energy Field Services for 18%. All
purchasers of the Partnership's oil and gas production are unrelated
third parties. In the event this purchaser 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 total oil and gas
production.
9. Subsequent Event
Subsequent to December 31, 2003, the Managing General Partner
announced that its Board of Directors had decided to explore a merger
or sale of the stock of the Company. The Board formed a Special
Committee of independent directors to oversee the sale process. The
Special Committee retained independent financial and legal advisors to
work closely with management to implement the sale process.
On May 3, 2004, the Managing General Partner entered into a cash
merger agreement to sell all of its stock to Clayton Williams Energy,
Inc. The cash merger price is being negotiated, but is expected to be
approximately $45 per share. The transaction, which is subject to
approval by the Managing General Partner's shareholders, is expected
to close no later than May 21, 2004.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
10. 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, 2001 49,000 69,000
Revisions of estimates in (20,000) (32,000)
place
Production (4,000) (6,000)
-------- --------
-- --
December 31, 2001 25,000 31,000
Revisions of estimates in 2,000 (1,000)
place
Production (4,000) (4,000)
-------- --------
-- --
December 31, 2002 23,000 26,000
Revisions of estimates in 11,000 7,000
place
Production (4,000) (5,000)
-------- --------
-- --
December 31, 2003 30,000 28,000
====== ======
Proved developed reserves -
December 31, 2001 25,000 31,000
====== ======
December 31, 2002 23,000 26,000
====== ======
December 31, 2003 30,000 28,000
====== ======
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, 2004. 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, 2004, 2003 and 2002 are an
average price of $31.81, $29.68 and $18.98 per barrel, respectively.
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, 2004, 2003 and 2002 are an average price of $5.49, $4.20
and $2.28 per Mcf, respectively.
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.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
10. Estimated Oil and Gas Reserves (unaudited) - continued
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. All of the proved reserves are included in the engineering
reports, which evaluate the Partnership's present reserves.
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2003, 2002 and 2001 is
presented below:
2003 2002 2001
---- ---- ----
Future cash inflows $ 1,113,00 805,000 553,000
0
Production, development and
abandonment costs 717,000 428,000 395,000
-------- -------- --------
---- ---- --
Future net cash flows 396,000 377,000 158,000
10% annual discount for
estimated
timing of cash flows 94,000 103,000 37,000
-------- -------- --------
---- ---- --
Standardized measure of
discounted
future net cash flows $ 302,000 274,000 121,000
======= ======= ======
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2003, 2002 and 2001 are as follows:
2003 2002 2001
---- ---- ----
Sales of oil and gas
produced,
net of production costs $ (72,000) (44,000) (66,000)
Changes in prices and (40,000) 174,000 (346,000
production costs )
Changes of production rates
(timing) and others 7,000 (7,000) 16,000
Revisions of previous
quantities estimates 106,000 18,000 (101,000
)
Changes in estimated future
development costs - -
Accretion of discount 27,000 12,000 56,000
Discounted future net
cash flows -
Beginning of year 274,000 121,000 562,000
-------- -------- --------
-- -- --
End of year $ 302,000 274,000 121,000
====== ====== ======
Future net cash flows were computed using year-end prices and costs
that related to existing proved oil and gas reserves in which the
Partnership has mineral interests.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
11. Selected Quarterly Financial Results - (unaudited)
Quarter
--------------------------------------
--------------------------------------
-
First Second Third Fourth
------ -------- ------- --------
--- -
2003:
Total revenues $ 42,713 48,914 36,008 34,167
Total expenses 46,431 37,308 34,337 20,633
Net income (loss) before
cumulative effect
of a change in (3,718) 11,606 1,671 13,534
accounting principle
Cumulative effect of SFAS 10,204 - - -
No. 143
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 6,486 11,606 1,671 13,534
======= ======= ======= =======
Per limited partner unit
amounts:
Income (loss) before $ (3.75) .82
cumulative effect 8.26 9.92
Cumulative effect 7.93 - - -
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 4.18 .82
8.26 9.92
======= ======= ======= =======
As discussed in Note 4, 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 reflect the change in depletion
method effective as of January 1, 2002.
Quarter
--------------------------------------
--------------------------------------
-
First Second Third Fourth
------ -------- ------- --------
--- -
2002:
Total revenues $ 18,477 31,744 25,395 29,479
Total expenses 24,343 25,068 21,650 31,092
-------- -------- -------- --------
---- ---- ---- ----
Net Income (loss) before
cumulative effect
of a change in (5,866) 6,676 3,745 (1,613)
accounting principle
Cumulative effect on
prior years (to
December 31, 2001) of
changing to a
different depletion 100,000 - - -
method
-------- -------- -------- --------
---- ---- ---- ----
Net income (loss) $ 94,134 6,676 3,745 (1,613)
======= ======= ======= =======
Per limited partner unit
amounts:
Income (loss) before
cumulative effect of a
change in accounting $ (5.13)
principle 4.42 2.43 (1.93)
Cumulative effect on
prior years (to
December 31, 2001) of
changing to a
different depletion 87.37 - - -
method
-------- -------- -------- --------
---- ---- ---- ----
Net income (loss) $ 82.24
4.42 2.43 (1.93)
======= ======= ======= =======
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of the year ended December 31, 2003, H.H. Wommack, III, President and
Chief Executive Officer of the Managing General Partner, and Bill E.
Coggin, Executive Vice President and Chief Financial Officer of the
Managing General Partner, evaluated the effectiveness of the Partnership's
disclosure controls and procedures. Based on their evaluation, they
believe that:
The disclosure controls and procedures of the Partnership were
effective in ensuring that information required to be disclosed by the
Partnership in the reports it files or submits under the Exchange Act
was recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms; and
The disclosure controls and procedures of the Partnership were
effective in ensuring that material information required to be
disclosed by the Partnership in the report it filed or submitted under
the Exchange Act was accumulated and communicated to the Managing
General Partner's management, including its President and Chief
Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
There has not been any change in the Partnership's internal control over
financial reporting that occurred during the year ended December 31, 2003
that has materially affected, or is reasonably likely to materially affect,
its internal control over financial reporting.
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 48 Chairman of the Board,
President, Director
and Chief Executive Officer
James N. Chapman(1) 41 Director
William P. Nicoletti(2) 58 Director
Joseph J. Radecki, Jr. 45 Director
(2)
Richard D. Rinehart(1) 68 Director
John M. White(2) 48 Director
Herbert C. Williamson, 55 Director
III(1)
Bill E. Coggin 49 Executive Vice President and
Chief Financial Officer
J. Steven Person 45 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 is associated with Regiment Capital Advisors, LLC, which he joined
in January 2003. Prior to Regiment, Mr. Chapman acted as a capital markets
and strategic planning consultant with private and public companies, as
well as hedge funds, across a range of industries. Prior to establishing an
independent consulting practice, Mr. Chapman worked for The Renco Group,
Inc. from December 1996 to December 2001. Prior to Renco, Mr. Chapman was
a founding principal of Fieldstone Private Capital Group in August 1990.
Prior to joining Fieldstone, Mr. Chapman worked for Bankers Trust Company
from July 1985 to August 1990, most recently in the BT Securities capital
markets area. Mr. Chapman serves as a member of the board of directors of
Anchor Glass Container Corporation, Davel Communications, Inc., Coinmach
Corporation, as well as a number of private companies.
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 is 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. He is also a director of MarkWest Energy
Partners, L.P., a business engaged in the gathering and processing of
natural gas and the fractionation and storage of natural gas liquids, and
Russell-Stanley Holdings, Inc., a manufacturer and marketer of steel and
plastic industrial containers. 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 RBX
Corporation, a manufacturer of rubber and plastic foam and other polymer
products. He previously served as a Director of Wherehouse Entertainment,
Inc., a music and video specialty retailer, 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 White has served as a director since April 19, 2002. Mr. White became
an equity analyst for Harris Nesbitt Gerard following the acquisition by
BMO Financial Group in 2003. He had joined BMO Nesbitt Burns in 1998,
responsible for high yield research on oil, gas and energy companies.
Previously, Mr. White worked at John S. Herold, Inc., an independent oil
and gas research and consulting firm, where he was responsible for fixed
income research on the oil and gas industry. His prior experience also
included four years managing a portfolio of oil and gas loans for The Bank
of Nova Scotia. Before entering financial services, Mr. White was with BP,
where he worked in exploration and production for seven years. At BP, his
experience was primarily in the basins of the Mid-Continent and Rocky
Mountain regions. Mr.White is a graduate of The University of Oklahoma.
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 46, 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 48, 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.
Code of Ethics
Neither the Partnership nor the Managing General Partner has adopted a code
of ethics for employees, or any principal executive officers, principal
financial officers, principal accounting officers or the Board of Directors
of the Managing General Partner. The Board of the Managing General Partner
believes that the Partnership's existing internal control procedures and
current business practices are adequate to promote ethical conduct and to
deter wrongdoing on the part of these executives. The Managing General
Partner of the Partnership intends to implement during 2004 a code of
ethics that will apply to these executives. In accordance with applicable
SEC rules, the code of ethics will be made publicly available.
Audit Committee
The current members of the Audit Committee of the Managing General Partner
are William P. Nicoletti, John M. White and Joseph J. Radecki, Jr. The
Board of Directors of the Managing General Partner has determined that Mr.
Nicoletti, the Chairman of the Audit Committee, meets the definition of an
"audit committee financial expert" under Item 401(h)(2) of Regulation S-K
and has also determined that all of the members of the Audit Committee,
including Mr. Nicoletti, meet the independence requirements of Section
10A(m)(3) of the Securities Exchange Act of 1934, as amended, and the rules
and regulations promulgated thereunder.
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
$9,400, $10,800 and $10,800 during 2003, 2002 and 2001 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
and Related Stockholders Matters
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 an eleven percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns 72 limited partner units, or 5.6% limited partner interest. The
Managing General Partner total percentage interest ownership in the
Partnership is 16.6%.
No officer or director of the Managing General Partner directly owns Units
in the Partnership. H. H. Wommack, III, as the individual general partner
of the Partnership, owns a one percent interest as a general partner. The
officers and directors of the Managing General Partner are considered
beneficial owners of the limited partner units acquired by the Managing
General Partner by virtue of their status as such. Beneficial ownership is
determined in accordance with the rules of the Securities and Exchange
Commission and includes voting or investment power with respect to the
limited partner units. To our knowledge, except under applicable community
property laws or as otherwise indicated, the persons named in the table
have sole voting and sole investment control with regard to all limited
partner units beneficially owned. We are presenting ownership information
as of December 31, 2003. A list of beneficial owners of limited partner
units, known to the Managing General Partner, is as follows:
Amount and
Nature of Percen
t
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------- ---------- ------
-------------- -------------- ------ -----
Limited Partnership Southwest Royalties, Directly 5.6%
Interest Inc. Owns
Managing General 72 Units
Partner
407 N. Big Spring
Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly 5.6%
Interest Owns
Chairman of the 72 Units
Board,
President, and CEO
of Southwest
Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring
Street
Midland, TX 79701
There are no arrangements known to the Managing General Partner, which may
at a subsequent date result in a change of control of the Partnership.
Item 13. Certain Relationships and Related Transactions
In 2003, the Managing General Partner received $9,400 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 $12,000 for administrative overhead
attributable to operating such properties during 2003.
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. Principal Accountant Fees and Services
The following table presents fees for professional audit services rendered
by KPMG, LLP for the audit of the Partnership's annual financial statements
for the years ended December 31, 2003 and 2002 and fees billed for other
services rendered by KPMG during those periods.
For the Year Ended December 2003
31, 2002
Audit Fees $9,056 $
4,763
Audit Related Fees -
-
Tax Fees -
-
All Other Fees -
-
TOTAL $9,056 $
4,763
The Audit Committee of the Managing General Partner reviewed and approved,
in advance, all audit and non-audit services provided by KPMG, LLP.
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 Sheets
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 Developmental Drilling
Fund 91-A, L.P., dated January 9, 1991.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1991.)
(b) Agreement of Limited
Partnership of Southwest Developmental Drilling
Fund 91-A, L.P. dated January 9, 1991.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1991.)
(c) Second Amended and Restated
Certificate of Limited Partnership of Southwest
Developmental Drilling Fund 91-A. L.P., dated as
of February 1, 1993. (Incorporated by reference
from Partnership's Form 10-K for the fiscal year
ended December 31, 1993.)
(d) Second Amended and Restated
Certificate of Limited Partnership of Southwest
Developmental Drilling Fund 91-A. L.P., dated as
of January 12, 1994. (Incorporated by reference
from Partnership's Form 10-K for the fiscal year
ended December 31, 1993.)
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Certification of Chief Executive Officer Pursuant to 18
U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
32.2 Certification of Chief Financial Officer Pursuant to 18
U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2003.
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 Developmental Drilling Fund 91-
A, L.P.,
a Delaware limited partnership
By: Southwest Royalties, Inc.,
Managing
General Partner
By: /s/ H. H. Wommack, III
------------------------------------------
- -----
H. H. Wommack, III, President
Date: May 12, 2004
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.
/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: May 12, 2004 Date: May 12, 2004
/s/ William P. Nicoletti /s/ James N. Chapman
- --------------------------- ------------------------
- -------------------- -----------------------
William P. Nicoletti, James N. Chapman,
Director Director
Date: May 10, 2004 Date: May 12, 2004
/s/ Richard D. Rinehart /s/ Joseph J. Radecki,
Jr.
- --------------------------- ------------------------
- -------------------- -----------------------
Richard D. Rinehart, Joseph J. Radecki, Jr.,
Director Director
Date: May 12, 2004 Date: May 12, 2004
/s/ Herbert C. Williamson,
III
- --------------------------- ------------------------
- -------------------- -----------------------
Herbert C. Williamson, III, John M. White, Director
Director
Date: May 11, 2004 Date:
SECTION 302 CERTIFICATION Exhibit 31.1
I, H.H. Wommack, III, certify that:
1.I have reviewed this annual report on Form 10-K of Southwest
Developmental Drilling Fund 91-
A, L.P.
2.Based on my knowledge, this 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 report;
3.Based on my knowledge, the financial statements, and
other financial information included in
this 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
report;
4.The registrant's other certifying officer(s) and I
are responsible for establishing and
maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and
15-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-
15(f) and 15d-15(f) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, 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 report is being prepared;
b)Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;
c)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have
disclosed, based on our most recent
evaluation of internal control over financial reporting,
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 and material weaknesses in the design or
operation of internal controls over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; 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 over financial reporting.
Date: May 12, 2004 /s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive
Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-
A, L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Bill E. Coggin, certify that:
1.I have reviewed this annual report on Form 10-K of
Southwest Developmental Drilling Fund 91-
A, L.P.
2.Based on my knowledge, this 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 report;
3.Based on my knowledge, the financial statements, and
other financial information included in
this 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
report;
4.The registrant's other certifying officer(s) and I
are responsible for establishing and
maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and
15-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-
15(f) and 15d-15(f) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, 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 report is being prepared;
b)Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;
c)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have
disclosed, based on our most recent
evaluation of internal control over financial reporting,
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 and material weaknesses in the design or
operation of internal controls over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; 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 over financial reporting.
Date: May 12, 2004 /s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-
A, L.P.
CERTIFICATION PURSUANT TO Exhibit 32.1
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 Developmental
Drilling Fund 91-A, L.P. (the "Company") on Form 10-K for the period ending
December 31, 2003 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: May 12, 2004
/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 Developmental Drilling Fund 91-A, L.P.
CERTIFICATION PURSUANT TO Exhibit 32.2
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 Developmental Drilling
Fund 91-A, L.P. (the "Company") on Form 10-K for the period ending December
31, 2003 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:
(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: May 12, 2004
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-A, L.P.