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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 92-A, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2387816
(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 47. The exhibits
begin on page 44.
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 35
9A. Controls and Procedures 35
Part III
10. Directors and Executive Officers of the Registrant 36
11. Executive Compensation 38
12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters 39
13. Certain Relationships and Related Transactions 40
14. Principal Accountant Fees and Services 40
Part IV
15. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 41
Signatures 42
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 92-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on May 5,
1992. The offering of limited and general partner interests began August
11, 1992 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 December 28, 1992, with the offering of limited
and general partner interests concluding December 31, 1992, with total
investor partner contributions of $1,407,000. The Managing General Partner
made a contribution to the capital of the Partnership at the conclusion of
the offering period in an amount equal to 1% of its net capital
contributions. The Managing General Partner contribution was $12,030, for
total capital contributions of $1,419,030. 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 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 leasehold
interests upon which drilling would be performed, and the marketing of
future anticipated 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 undeveloped 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 will be 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 76% 24%
2002 75% 25%
2001 72% 28%
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 of 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. Three purchasers accounted for
91% of the Partnership's total oil and gas production during 2003: Plains
Marketing LP for 60%, Duke Energy Field Services LP 18% and Navajo Refining
Company, Inc. for 13%. Contracts for 2003 with these major purchasers
cover time periods ranging from month to month contracts up to year-year
contract periods. Prices received from these major purchasers ranged from
a low of $29.51 per Bbl to a high of $29.72 per Bbl and $4.73 per mcf.
Three purchasers accounted for 95% of the Partnership's total oil and gas
production during 2002: Plains Marketing LP for 59%, Duke Energy Field
Services LP for 19% and Navajo Refining Company, Inc. for 17%. Contracts
for 2002 with these major purchasers cover time periods ranging from month
to month contracts up to year-year contract periods. Prices received from
these major purchasers ranged from a low of $22.73 per Bbl to a high of
$23.02 per Bbl and $2.86 per mcf. Three purchasers accounted for 93% of
the Partnership's total oil and gas production during 2001: Plains
Marketing LP for 58%, Duke Energy Field Services for 21% and Navajo
Refining Company, Inc. for 14%. Contracts for 2001 with these major
purchasers cover time periods ranging from month to month contracts up to
year-year contract periods. Prices received from these major purchasers
ranged from a low of $27.00 per Bbl to a high of $27.33 per Bbl and $4.90
per mcf. 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 drilling prospects and drilling activities, it is not
subject to competition from other oil and gas property purchasers. See
Item 2, Properties.
Factors that may adversely affect the Partnership include delays in
completing arrangements for the sale of production, availability of a
market for production, rising operating costs of producing oil and gas and
complying with applicable water and air pollution control statutes,
increasing costs and difficulties of transportation, and marketing of
competitive fuels. Moreover, domestic oil and gas must compete with
imported oil and gas and with coal, atomic energy, hydroelectric power and
other forms of energy.
Regulation
Oil and Gas Production - The production and sale of oil and gas is subject
to federal and state governmental regulation in several respects, such as
existing price controls on natural gas and possible price controls on crude
oil, regulation of oil and gas production by state and local governmental
agencies, pollution and environmental controls and various other direct and
indirect regulation. Many jurisdictions have periodically imposed
limitations on oil and gas production by restricting the rate of flow for
oil and gas wells below their actual capacity to produce and by imposing
acreage limitations for the drilling of wells. The federal government has
the power to permit increases in the amount of oil imported from other
countries and to impose pollution control measures. Various aspects of the
Partnership's oil and gas activities are regulated by administrative
agencies under statutory provisions of the states where such activities are
conducted and by certain agencies of the federal government for operations
on Federal leases. The regulatory burden on the oil and gas industry
increases the Partnership's cost of doing business, and, consequently,
affects its profitability.
Regulation of Sales and Transportation of Natural Gas. Our sales of
natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation
are subject to extensive regulation. In recent years, the FERC has
undertaken various initiatives to increase competition within the natural
gas industry. As a result of initiatives like FERC Order No. 636, issued in
April 1992, the interstate natural gas transportation and marketing system
has been substantially restructured to remove various barriers and
practices that historically limited non-pipeline natural gas sellers,
including producers, from effectively competing with interstate pipelines
for sales to local distribution companies and large industrial and
commercial customers. The most significant provisions of Order No. 636
require that interstate pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all
natural gas supplies. In many instances, the results of Order No. 636 and
related initiatives have been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. While the
United States Court of Appeals upheld most of Order No. 636, certain
related FERC orders, including the individual pipeline restructuring
proceedings, are still subject to judicial review and may be reversed or
remanded in whole or in part. While the outcome of these proceedings cannot
be predicted with certainty, we do not believe that we will be affected
materially differently than its competitors.
The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-
service rate making methodology to establish the rates interstate pipelines
may charge for their services. A number of pipelines have obtained FERC
authorization to charge negotiated rates as one such alternative. In
February 1997, the FERC announced a broad inquiry into issues facing the
natural gas industry to assist the FERC in establishing regulatory goals
and priorities in the post-Order No. 636 environment. Similarly, the Texas
Railroad Commission has been reviewing changes to its regulations governing
transportation and gathering services provided by intrastate pipelines and
gatherers. While the changes being considered by these federal and state
regulators would affect us only indirectly, they are intended to further
enhance competition in natural gas markets. We cannot predict what further
action the FERC or state regulators will take on these matters, however, we
do not believe that it will be affected by any action taken materially
differently than other natural gas producers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will
continue.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and gas liquids by us are not currently regulated and are made at market
prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market.
Environmental and Health Controls. Extensive federal, state and local
regulatory and common laws regulating the discharge of materials into the
environment or otherwise relating to the protection of the environment
affect our oil and natural gas operations. Numerous governmental
departments issue rules and regulations to implement and enforce such laws,
which are often difficult and costly to comply with and which carry
substantial civil and even criminal penalties for failure to comply. Some
laws, rules and regulations relating to protection of the environment may,
in certain circumstances, impose strict liability for environmental
contamination, rendering a person liable for environmental damages and
cleanup costs without regard to negligence or fault on the part of such
person. Other laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist or even
prohibit exploration and production activities in sensitive areas. In
addition, state laws often require various forms of remedial action to
prevent pollution, such as closure of inactive pits and plugging of
abandoned wells. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and consequently affects our
profitability. We believe that we are in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse
impact on our operations. However, environmental laws and regulations have
been subject to frequent changes over the years, and the imposition of more
stringent requirements could have a material adverse effect upon our
capital expenditures, earnings or competitive position. Additionally,
given the intense litigation environment in the United States, a threat
exists of lawsuits alleging personal injury and property damage from
environmental contamination alleged to be created by us or related
entities. Potential liability in such lawsuits can include not only
compensatory, but substantial punitive damages as well. We are not aware
of any such suits currently pending or threatened.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault on certain classes of persons that are considered to be
responsible for the release of a "hazardous substance" into the
environment. These persons include the current or former owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances. Under CERCLA
such persons may be subject to joint and several liability for the costs of
investigating and cleaning up hazardous substances that have been released
into the environment, for damages to natural resources and for the costs of
certain health studies. In addition, companies that incur liability
frequently also confront third party claims because it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by hazardous substances or
other pollutants released into the environment from a polluted site.
Potential liability also exists under CERCLA for natural resource damage.
A Natural Resource Damage Action (NRDA) could result in liability being
assessed for restoration to natural resources.
The Federal Oil Pollution Act of 1990 ("OPA") regulates the release of oil
into water or other areas designated by the statute. A release could
result in our being held responsible for the cost of remediating the
release, OPA specified damages and natural resource damages. The extent of
such liability could be extensive. A release of oil in harmful quantities
or other materials into water or other specified areas could also result in
our being held responsible under the Clean Water Act ("CWA") for the costs
of remediation, and any civil and criminal fines and penalties.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of solid and hazardous
wastes and can require cleanup of abandoned hazardous waste disposal sites
as well as waste management areas operating facilities. RCRA currently
excludes drilling fluids, produced waters and other wastes associated with
the exploration, development or production of oil and natural gas from
regulation as "hazardous waste." Disposal of such non-hazardous oil and
natural gas exploration, development and production wastes usually are
regulated by state law. Other wastes handled at exploration and production
sites or used in the course of providing well services may not fall within
this exclusion. Moreover, stricter standards for waste handling and
disposal may be imposed on the oil and natural gas industry in the future.
From time to time legislation is proposed in Congress that would revoke or
alter the current exclusion of exploration, development and production
wastes from the RCRA definition of "hazardous wastes" thereby potentially
subjecting such wastes to more stringent handling, disposal and cleanup
requirements. If such legislation were enacted it could have a significant
impact on the operating costs of Southwest and Sierra, as well as the oil
and natural gas industry and well servicing industry in general. The impact
of future revisions to environmental laws and regulations cannot be
predicted. In addition, if our operations were to trigger regulation under
RCRA, we could be required to satisfy certain financial criteria to ensure
financial ability to comply with RCRA regulations. Proof of financial
responsibility could be required in the form of dedicated trust funds,
irrevocable letters of credit, posting of bonds, etc.
The Federal Clean Water Act ("CWA") contains provisions that may result in
the imposition of certain water pollution control requirements with respect
to water releases from our operations. We may be required to incur certain
capital expenditures in the next several years for water pollution control
equipment in connection with obtaining and maintaining National Pollutant
Discharge Elimination Systems ("NPDES") permits. However, we believe our
operations will not be materially adversely affected by any such
requirements, and the requirements are not expected to be any more
burdensome to us than to other similarly situated companies involved in oil
and natural gas exploration and production activities or well surfacing
activities.
Our operations are also subject to the federal Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from
our operations. We may be required to incur certain capital expenditures in
the next several years for air pollution control equipment in connection
with obtaining and maintaining operating permits and approvals for air
emissions. However, we believe our operations will not be materially
adversely affected by any such requirements, and the requirements are not
expected to be any more burdensome to us than to other similarly situated
companies involved in oil and natural gas exploration and production
activities or well servicing activities.
We maintain insurance against "sudden and accidental" occurrences, which
may cover some, but not all, of the environmental risks described above.
Most significantly, the insurance we maintain will not cover the risks
described above which occur over a sustained period of time. Further, there
can be no assurance that such insurance will continue to be available to
cover all such costs or that such insurance will be available at premium
levels that justify its purchase. The occurrence of a significant event
not fully insured or indemnified against could have a material adverse
effect on our financial condition and operations.
Limited partners should be aware that the assessment of liability
associated with environmental liabilities is not always correlated to the
value of a particular project. Accordingly, liability associated with the
environment under local, state, or federal regulations, particularly clean
ups under CERCLA, can exceed the value of our investment in the associated
site.
Regulation of Oil and Natural Gas Exploration and Production. Our
exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulations
include requiring permits and drilling bonds for the drilling of wells,
regulating the location of wells, the method of drilling and casing wells,
and the surface use and restoration of properties upon which wells are
drilled. Many states also have statutes or regulations addressing
conservation matters, including provisions for the utilization or pooling
of oil and natural gas properties, the establishment of maximum rates of
production from oil and natural gas wells and the regulation of spacing,
plugging and abandonment of such wells. Some state statutes limit the rate
at which oil and natural gas can be produced from our properties.
Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a staff of geologists, engineers, accountants, landmen and clerical staff
who engage in Partnership activities and operations and perform additional
services for the Partnership as needed. In addition to the Managing
General Partner's staff, the Partnership engages independent consultants
such as petroleum engineers and geologists as needed. As of December 31,
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 leasehold was to be
acquired, the Managing General Partner considered such criteria as
estimated drilling costs, estimated oil and gas reserves, estimated cash
flow from the sale of future production, present and future prices of oil
and gas, the extent of undeveloped and unproved reserves and the
availability of markets.
As of December 31, 2003, the Partnership possessed an interest in oil and
gas properties located in Ward County of Texas and Lea and Eddy Counties of
New Mexico. These properties consist of various interests in 9 wells.
Due to the Partnership's objective of maintaining current operations
without engaging in the additional 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 properties in which the Partnership has an
interest:
Date
Purchased No. of Proved Reserves*
Name and and Wells Oil Gas
Location Interest (bbls) (mcf)
- ------------- ----------- -------- -------- --------
- ------------ ------ --- ------ ------
Mobil Fee G 12/92 at 1 23,000 4,000
#1
Ward County, 100% 23,000(1 4,000(1)
Texas )
working
interest
Mobil Fee H 12/92 at 1 43,000 158,000
#1
Ward County, 100% 43,000(1 158,000(
Texas ) 1)
working
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 $31.76 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 $5.30 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.
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.
The Managing General Partner has the right, but not the obligation in
accordance with the obligations set forth in 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 Nations Bank, 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 under
the partnership agreement.
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 July 2003, the Managing General Partner purchased a total of 10
limited partner units from limited partners at an average base price of
$453.08 per unit. In 2002 and 2001, no limited partner units were
purchased by the Managing General Partner. The discretionary repurchases
were made based upon the partnership agreement.
Number of Limited and General Partner Interest Holders
As of December 31, 2003, there were 105 holders of limited partner units.
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 $168,665, with $150,112
distributed to the investor partners and $18,553 to the Managing General
Partners. For the year ended December 31, 2003, distributions of $106.69
per investor partner unit were made, based upon 1,407 investor partner
units outstanding. During 2002, distributions were made totaling $112,957,
with $100,532 distributed to the investor partners and $12,425 to the
Managing General Partners. For the year ended December 31, 2002,
distributions of $71.45 per investor partner unit were made, based upon
1,407 investor partner units outstanding. During 2001, distributions were
made totaling $208,798, with $185,830 distributed to the investor partners
and $22,968 to the Managing General Partners. For the year ended December
31, 2001, distributions of $132.08 per investor partner unit were made,
based upon 1,407 investor partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the year ended December 31, 2003,
2002, 2001, 2000 and 1999 should be read in conjunction with the financial
statements included in Item 8:
Year ended December 31,
--------------------------------------------
----
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Revenues $ 349,284 275,362 333,192 372,553 249,965
Net income before
cumulative effects
of accounting changes 156,673 120,581 160,893 217,640 112,767
Net income 153,929 117,581 160,893 217,640 112,767
Partners' share of net
income:
Managing General Partner 18,472 14,804 20,338 25,590 14,274
Investor partners 135,457 102,777 140,555 192,050 98,493
Investor partners' net
income per unit
before cumulative
effects of
accounting changes 98.01
75.18 99.90 136.50 70.00
Investor partners' net
income (loss) per unit 96.27
73.05 99.90 136.50 70.00
Investor partners' cash
distributions per unit 106.69
71.45 132.08 142.10 53.77
Total assets $ 249,981 235,993 231,369 279,195 286,195
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 92-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on May 5,
1992. The offering of limited and general partner interests began August
11, 1992 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 December 28, 1992, with the offering of limited
and general partner interests concluding December 31, 1992, with total
investor partner contributions of $1,407,000. The Managing General Partner
made a contribution to the capital of the Partnership at the conclusion of
the offering period in an amount equal to 1% of its net capital
contributions. The Managing General Partner contribution was $12,030.
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
to enhance production. The partnership will most likely experience the
historical production decline, which has approximated 10% per year.
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.
Results of Operations
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 $ 30.12 23%
barrel of oil 24.56
Average price per mcf $ 4.67 53%
of gas 3.05
Oil production in 8,700 8,410 3%
barrels
Gas production in mcf 17,500 22,000 (20%)
Oil and gas revenue $ 343,751 273,741 26%
Production expense $ 153,850 123,272 25%
Partnership $ 168,665 112,957 49%
distributions
Limited partner $ 150,112 100,532 49%
distributions
Per unit distribution $ 106.69 49%
to limited partners 71.45
Number of limited 1,407 1,407
partner units
Revenues
The Partnership's oil and gas revenues increased to $343,751 from $273,741
for the years ended December 31, 2003 and 2002, respectively, an increase
of 26%. 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 23%, or $5.56 per barrel, resulting in
an increase of approximately $48,400 in revenues. Oil sales represented
76% of total oil and gas sales during the year ended December 31, 2003
as compared to 75% 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 53%, or $1.62 per mcf, resulting in
an increase of approximately $28,400 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $76,800. 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 290 barrels or 3% during the
year ended December 31, 2003 as compared to the year ended December 31,
2002, resulting in an increase of approximately $7,100 in revenues.
Gas production decreased approximately 4,500 mcf or 20% during the same
period, resulting in a decrease of approximately $13,700 in revenues.
The net total decrease in revenues due to the change in production is
approximately $6,600. The decrease in gas volumes is due to the sharp
production decline on one well.
3. Other income in the amount of $5,533 for 2003 primarily represents
litigation settlement income from a class action lawsuit, where two
purchasers were underpaying for certain types of oil in certain
locations for the time periods of 1988-1998.
Costs and Expenses
Total costs and expenses increased to $192,611 from $154,781 for the years
ended December 31, 2003 and 2002, respectively, an increase of 24%. The
increase is the result of the addition of accretion expense, higher lease
operating costs and general and administrative expense.
1. Lease operating costs and production taxes were 25% higher, or
approximately $30,600 more during the year ended December 31, 2003 as
compared to the year ended December 31, 2002. The increase in lease
operating costs are due to increased well repairs on two wells and
compressor charges on one well and an increase in production taxes due to
an increase in oil and gas 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 29%
or approximately $5,100 during the year ended December 31, 2003 as
compared to the year ended December 31, 2002. The increase in general
and administrative expense is due to an increase in independent
accounting review and audit fees.
3. Depletion expense was $14,000 for the year ended December 31, 2003 the
same as 2002. The year ended December 31, 2003, was $1.21 applied to
11,617 BOE as compared to $1.16 applied to 12,077 BOE for the same
period in 2002.
Cumulative effect of change in accounting principle
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 $23,838, a long term liability of
approximately $26,582 and a loss of approximately $2,744 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 $28,708, and the increase in the balance from January 1,
2003 of $2,126 is due to accretion expense. The pro forma amounts of the
asset retirement obligation as of December 31, 2002, 2001 and 2000, were
approximately $26,582, $24,626 and $22,814, 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.
Results of Operations
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 $ 24.56 (3%)
barrel of oil 25.25
Average price per mcf $ 3.05 (25%)
of gas 4.08
Oil production in 8,410 9,460 (11%)
barrels
Gas production in mcf 22,000 23,000 (4%)
Oil and gas revenue $ 273,741 332,643 (18%)
Production expense $ 123,272 131,781 (6%)
Partnership $ 112,957 208,798 (46%)
distributions
Limited partner $ 100,532 185,830 (46%)
distributions
Per unit distribution $ 71.45 (46%)
to limited partners 132.08
Number of limited 1,407 1,407
partner units
Revenues
The Partnership's oil and gas revenues decreased to $273,741 from $332,643
for the years ended December 31, 2002 and 2001, respectively, a decrease of
18%. 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 $.69 per barrel, resulting in a
decrease of approximately $5,800 in revenues. Oil sales represented 75%
of total oil and gas sales during the year ended December 31, 2002 as
compared to 72% 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 25%, or $1.03 per mcf, resulting in
a decrease of approximately $22,700 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $28,500. The market price
for oil and gas has been extremely volatile over the past decade and
management expects a certain amount of volatility to continue in the
foreseeable future.
2. Oil production decreased approximately 1,050 barrels or 11% during the
year ended December 31, 2002 as compared to the year ended December 31,
2001, resulting in a decrease of approximately $26,500 in revenues.
Gas production decreased approximately 1,000 mcf or 4% during the same
period, resulting in a decrease of approximately $4,100 in revenues.
The total decrease in revenues due to the change in production is
approximately $30,600.
Costs and Expenses
Total costs and expenses decreased to $154,781 from $172,299 for the years
ended December 31, 2002 and 2001, respectively, a decrease of 10%. The
decrease is the result of lower lease operating costs and depletion
expense, partially offset by an increase general and administrative
expense.
2. Lease operating costs and production taxes were 6% lower, or
approximately $8,500 less during the year ended December 31, 2002 as
compared to the year ended December 31, 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 6%
or approximately $1,000 during the year ended December 31, 2002 as
compared to the year ended December 31, 2001.
3. Depletion expense decreased to $14,000 for the year ended December 31,
2002 from $24,000 for the same period in 2001. This represents a
decrease of 42%. 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 resulted in no change to 2002 depletion
expense, however, it decreased 2002 net income by $3,000. See Note 4
of the notes to the Partnership's financial statements.
The major factor in the decrease in depletion expense between the
comparative periods was the increase in the price of oil and gas used
to determine the Partnership's reserves for January 1, 2003 as compared
to 2002, which provided more economically recoverable proved reserves
at January 1, 2003 which caused the depletion rate per equivalent unit
produced to decline. Also, as discussed above, the total equivalent
units produced in 2002 declined from 2001.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2003, 2002 and 2001
was $153,929, $117,581 and $160,893, respectively. Partnership
distributions for the years ended December 31, 2003, 2002 and 2001 were
$168,665, $112,957 and $208,798, respectively. These differences are
indicative of the changes in oil and gas prices, production and property
during 2003, 2002 and 2001.
The sources for the 2003 distributions of $168,665 were oil and gas
operations of approximately $172,300 and the change in oil and gas
properties of approximately $(600), resulting in excess cash for
contingencies or subsequent distributions. The sources for the 2002
distributions of $112,957 were oil and gas operations of approximately
$124,000 and the change in oil and gas properties of approximately $(10),
resulting in excess cash for contingencies or subsequent distributions.
The sources for the 2001 distributions of $208,798 were oil and gas
operations of approximately $197,000 and the change in oil and gas
properties of approximately $1,400, with the balance from available cash on
hand at the beginning of the period.
Total distributions during the year ended December 31, 2003 were $168,665
of which $150,112 was distributed to the investor partners and $18,553 to
the Managing General Partners. The per unit distribution to investor
partners during the same period was $106.69. Total distributions during
the year ended December 31, 2002 were $112,957 of which $100,532 was
distributed to the investor partners and $12,425 to the Managing General
Partners. The per unit distribution to investor partners during the same
period was $71.45. Total distributions during the year ended December 31,
2001 were $208,798 of which $185,830 was distributed to the investor
partners and $22,968 to the Managing General Partners. The per unit
distribution to investor partners during the same period was $132.08.
Cumulative cash distributions of $1,867,975 have been made to the general
and limited partners as of December 31, 2003. As of December 31, 2003,
$1,662,874 or $1,181.68 per investor partner unit, has been distributed to
the investor partners, representing a 100% return of capital and a 18%
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 $172,300 in
2003 compared to $124,000 in 2002 and approximately $197,000 in 2001.
Cash flows (used in) provided by investing activities were approximately
$(600) in 2003 compared to $(10) in 2002 and approximately $1,400 in 2001.
The primary use of the 2003 cash flow from investing activities was the
change in oil and gas properties.
Cash flows used in financing activities were approximately $168,600 in 2003
compared to $113,000 in 2002 and approximately $208,700 in 2001. The only
use in the 2003 financing activities was the distributions to partners.
As of December 31, 2003, the Partnership had $70,700 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
Statement 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 92-A
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Developmental
Drilling Fund 92-A (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 92-A 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 92-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2003 and 2002
2003 2002
---- ----
Assets
- ------
Current assets:
Cash and cash equivalents $ 30,713 27,569
Receivable from Managing 39,984 39,532
General Partner
-------- --------
---- ----
Total current assets 70,697 67,101
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 1,326,16 1,313,13
8 2
Less accumulated
depreciation,
depletion and 1,146,88 1,144,24
amortization 4 0
-------- --------
---- ----
Net oil and gas 179,284 168,892
properties
-------- --------
---- ----
$ 249,981 235,993
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ----
Current liability - $ 95 79
distribution payable
-------- --------
---- ----
Asset retirement obligation 28,708 9
-------- --------
---- ----
Partners' equity:
Managing General Partner 30,222 30,303
Investor partners 190,956 205,611
-------- --------
---- ----
Total partners' equity 221,178 235,914
-------- --------
---- ----
$ 249,981 235,993
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-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 $ 343,751 273,741 332,643
Interest income from - 92 549
operations
Other 5,533 1,529 -
-------- -------- --------
-- -- --
349,284 275,362 333,192
-------- -------- --------
-- -- --
Expenses
- ------------
Production 153,850 123,272 131,781
General and administrative 22,635 17,509 16,518
Accretion of asset retirement 2,126 - -
obligation
Depreciation, depletion and 14,000 14,000 24,000
amortization
-------- -------- --------
-- -- --
192,611 154,781 172,299
-------- -------- --------
-- -- --
Net income before cumulative
effect
of accounting changes 156,673 120,581 160,893
Cumulative effect of change in
accounting
principle - SFAS No. 143 - (2,744) - -
See Note 3
Cumulative effect of change in
accounting principle
- change in depletion method - (3,000) -
- - See Note 4
-------- -------- --------
-- -- --
Net income $ 153,929 117,581 160,893
====== ====== ======
Net income allocated to:
Managing General Partner $ 18,472 14,804 20,338
====== ====== ======
Investor partners $ 135,457 102,777 140,555
====== ====== ======
Per investor partner unit $ 98.01
before cumulative effect 75.18 99.90
Cumulative effects per (1.74) (2.13) -
investor partner unit
-------- -------- --------
-- -- --
Per investor partner unit $ 96.27
73.05 99.90
====== ====== ======
Pro forma amounts assuming
changes are applied
retroactively (See Notes 3
and 4 for details):
Net income before cumulative $ - 118,625 163,081
effect
====== ====== ======
Per investor partner unit $ - 73.94 101.59
(1,407.0 units)
====== ====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
Years ended December 31, 2003, 2002 and 2001
Managing
General Investor
Partner Partners Total
-------- -------- -----
Balance at December 31, 2000 $ 30,554 248,641 279,195
Net income 20,338 140,555 160,893
Distributions (22,968) (185,830 (208,798
) )
-------- -------- --------
-- --- ---
Balance at December 31, 2001 27,924 203,366 231,290
Net income 14,804 102,777 117,581
Distributions (12,425) (100,532 (112,957
) )
-------- -------- --------
-- --- ---
Balance at December 31, 2002 30,303 205,611 235,914
Net income 18,472 135,457 153,929
Distributions (18,553) (150,112 (168,665
) )
-------- -------- --------
-- --- ---
Balance at December 31, 2003 $ 30,222 190,956 221,178
====== ====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
Cash flows from operating
activities:
Cash received from oil and gas $ 337,671 257,856 353,274
sales
Cash paid to Managing General
Partner
for administrative fees and
general
and administrative overhead (170,857 (135,451 (156,854
) ) )
Interest received - 92 549
Miscellaneous settlement 5,533 1,529 -
-------- -------- --------
-- -- --
Net cash provided by 172,347 124,026 196,969
operating activities
-------- -------- --------
-- -- --
Cash flows from investing
activities:
Addition to oil and gas (554) (8) -
properties
Sale of equipment - - 1,393
-------- -------- --------
-- -- --
Net cash (used in) provided (554) (8) 1,393
by investing activities
-------- -------- --------
-- -- --
Cash flows used in financing
activities:
Distributions to partners (168,649 (112,957 (208,719
) ) )
-------- -------- --------
-- -- --
Net increase (decrease) in cash 3,144 11,061 (10,357)
and cash equivalents
Beginning of period 27,569 16,508 26,865
-------- -------- --------
-- -- --
End of period $ 30,713 27,569 16,508
====== ====== ======
Reconciliation of net income to
net
cash provided by operating
activities:
Net income $ 153,929 117,581 160,893
Adjustments to reconcile net
income to
net cash provided by operating
activities:
Depreciation, depletion and 14,000 14,000 24,000
amortization
Accretion of asset retirement 2,126 - -
obligation
Cumulative effect of change in 2,744 3,000 -
accounting principle
(Increase) decrease in (6,080) (15,885) 20,631
receivables
Increase (decrease) in 5,628 5,330 (8,555)
payables
-------- -------- --------
-- -- --
Net cash provided by operating $ 172,347 124,026 196,969
activities
====== ====== ======
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption
of SFAS No. 143 $ 23,838 - -
====== ====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 92-A, L.P. was organized under
the laws of the state of Delaware on May 5, 1992, for the purpose of
engaging primarily in the business of drilling developmental and
exploratory wells, to produce and market crude oil and natural gas
produced from such properties, and acquire leases, which contain
drilling prospects. The activities of the Partnership should continue
for a term of 50 years, unless terminated at an earlier date as
provided for in the Partnership Agreement. The Partnership
anticipates selling 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 92-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 over or
under deliveries of gas. Under this method, the Partnership records
revenues based on the payments it has received for sales from
purchasers. As of December 31, 2003 and 2002, the Partnership was not
over or under produced.
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 assets at December 31,
2003 and 2002 was $170,944 and $172,009, 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.
Investor Partner Units
As of December 31, 2003, 2002 and 2001, there were 1,407 investor
units outstanding held by 105 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 92-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 $23,838, a long term liability of
approximately $26,582 and a loss of approximately $2,744 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 $28,708, and the
increase in the balance from January 1, 2003 of $2,126 is due to
accretion expense. The pro forma amounts of the asset retirement
obligation as of December 31, 2002, 2001 and 2000, were approximately
$26,582, $24,626 and $22,814, 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 $ 118,625 159,081
====== ======
Per investor partner unit $ 73.94 98.75
(1,407.0 units)
====== ======
Net income $ 115,625 159,081
====== ======
Per investor partner unit $ 71.80 98.75
(1,407.0 units)
====== ======
Southwest Developmental Drilling Fund 92-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 $3,000 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 $ 164,893
======
Per investor partner unit $ 102.74
(1,407.0 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
Nations Bank, 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 92-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 $23,100,
$23,700 and $23,600 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 an
administrative fee of $12,000 during 2003, 2002 and 2001 for
reimbursement of 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 $43,600 and $39,500 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 purchaser, where the loss of one would
have a material adverse impact on the Partnership. Three purchasers
accounted for 91% of the Partnership's total oil and gas production
during 2003: Plains Marketing LP for 60%, Duke Energy Field Services
LP 18% and Navajo Refining Company, Inc. for 13%. Three purchasers
accounted for 95% of the Partnership's total oil and gas production
during 2002: Plains Marketing LP for 59%, Duke Energy Field Services
LP for 19% and Navajo Refining Company, Inc. for 17%. Three
purchasers accounted for 93% of the Partnership's total oil and gas
production during 2001: Plains Marketing LP for 58%, Duke Energy Field
Services for 21% and Navajo Refining Company, Inc. for 14%. 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 92-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 110,000 242,000
Revisions of estimates in (22,000) 26,000
place
Production (9,000) (23,000)
-------- --------
-- --
December 31, 2001 79,000 245,000
Production 17,000 13,000
Revisions of estimates in (8,000) (22,000)
place
-------- --------
-- --
December 31, 2002 88,000 236,000
Production (9,000) (18,000)
Revisions of estimates in 1,000 48,000
place
-------- --------
-- --
December 31, 2003 80,000 266,000
====== ======
Proved developed reserves -
December 31, 2001 79,000 245,000
====== ======
December 31, 2002 88,000 236,000
====== ======
December 31, 2003 80,000 266,000
====== ======
All of the Partnership's reserves are located within the continental
United States.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
10. Estimated Oil and Gas Reserves (unaudited) - continued
*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 $31.76, $29.67 and $18.90 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 $5.30, $4.49
and $2.34 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.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. 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.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
10. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2003, 2002 and 2001 is
presented below:
2003 2002 2001
---- ---- ----
Future cash inflows $ 3,955,00 3,682,00 2,059,00
0 0 0
Production, development and
abandonment costs 2,113,00 1,945,00 1,334,00
0 0 0
-------- -------- --------
---- ---- ----
Future net cash flows 1,842,00 1,737,00 725,000
0 0
10% annual discount for
estimated
timing of cash flows 767,000 680,000 260,000
-------- -------- --------
---- ---- ----
Standardized measure of
discounted
future net cash flows $ 1,075,00 1,057,00 465,000
0 0
======= ======= =======
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 $ (190,000 (150,000 (201,000
) ) )
Changes in prices and 94,000 549,000 (1,178,0
production costs 00)
Changes of production rates
(timing) and others (69,000) (12,000) 177,000
Revisions of previous
quantities estimates 78,000 159,000 (69,000)
Accretion of discount 105,000 46,000 158,000
Discounted future net
cash flows -
Beginning of year 1,057,00 465,000 1,578,00
0 0
-------- -------- --------
---- ---- ----
End of year $ 1,075,00 1,057,00 465,000
0 0
======= ======= =======
Future net cash flows were computed using year-end prices and costs
that related to existing proved oil and gas reserves in which the
Partnership has mineral interests.
Southwest Developmental Drilling Fund 92-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 $ 102,069 88,470 75,271 83,474
Total expenses 38,013 52,123 53,468 49,007
Cumulative effect of SFAS (2,744) - - -
No. 143
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 61,312 36,347 21,803 34,467
======= ======= ======= =======
Per limited partner unit
amounts:
Net income before $ 40.21
cumulative effect 22.68 13.56 21.56
Cumulative effect of SFAS (1.74) - - -
No. 143
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 38.47
22.68 13.56 21.56
======= ======= ======= =======
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 $ 53,515 70,937 76,111 74,799
Total expenses 37,583 34,294 40,738 42,166
-------- -------- -------- --------
---- ---- ---- ----
Net income before
cumulative effect of
a change in accounting 15,932 36,643 35,373 32,633
principle
Cumulative effect on
prior years (to
December 31, 2001) of
changing to a
different depletion (3,000) - - -
method
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 12,932 36,643 35,373 32,633
======= ======= ======= =======
Per limited partner unit
amounts:
Net income before
cumulative effect of a
change in accounting $ 9.77
principle 22.87 22.14 20.40
Cumulative effect on
prior years (to
December 31, 2001) of
changing to a
different depletion (2.13) - - -
method
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 7.64
22.87 22.14 20.40
======= ======= ======= =======
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,
it 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. Radecki 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
$12,000 during 2003, 2002 and 2001 as an 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 Stockholder Matters
There are no investor partners other than as listed below, who own of
record, or are known by the Managing General Partner to beneficially own,
more than five percent of the Partnership's investor partner interests.
Amount and
Nature of Percen
t
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------- ---------- ------
-------------- -------------- ------ -----
Limited Partnership John H. Beckerle, 90 limited 5.7%
Units Estate Trust partnershi
2653 South Kihei Road p units
Unit 211
Kihei Maui, HI 96753
The Managing General Partner owns an eleven percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns 15.0 limited partner units, or .95% limited partner interest. The
Managing General Partner total percentage interest ownership in the
Partnership is 11.9%.
No officer or director of the Managing General Partner directly owns Units
in the Partnership. 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. 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 .95%
Interest Inc. Owns
Managing General 15.0 Units
Partner
407 N. Big Spring
Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly .95%
Interest Owns
Chairman of the 15.0 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 $12,000 as an administrative
fee. This amount is part of the general and administrative expenses
incurred by the Partnership.
In some instances the Managing General Partner and certain officers and
employees may be working interest owners in an oil and gas property in
which the Partnership also has a working interest. Certain properties in
which the Partnership has an interest are operated by the Managing General
Partner, who was paid approximately $23,100 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 Sheet
Statement of Changes in Partners' Equity
Statement of Cash Flows
Notes to Financial Statements
(2) Schedules I through XIII are omitted
because they are not applicable, or because the required
information is shown in the financial statements or the
notes thereto.
(3) Exhibits:
Exhibit 4(a): Certificate of Limited
Partnership of Southwest Developmental
Drilling Fund 92-A, L.P., dated May 5,
1992 (Incorporated by reference from
Partnership's Form 10-K for the fiscal
year ended December 31, 1992).
Exhibit 4(b): Agreement of Limited
Partnership of Southwest Developmental
Drilling Fund 92-A, L.P. dated May 5, 1992
(Incorporated by reference from
Partnership's Form 10-K for the fiscal
year ended December 31, 1992).
Exhibit 4(c): First Amendment to
Amended and Restated Certificate of
Limited Partnership of Southwest
Developmental Drilling Fund 92-A. L.P.,
dated as of February 22, 1993
(Incorporated by reference from Partner
ship's Form 10-K for the fiscal year ended
December 31, 1993).
Exhibit 4(d): Second Amendment to
Amended and Restated Certificate of
Limited Partnership of Southwest
Developmental Drilling Fund 92-A. L.P.,
dated as of March 26, 1993 (Incorporated
by reference from Partnership's Form 10-K
for the fiscal year ended December 31,
1993).
Exhibit 4(e): Second Amended and
Restated Certificate of Limited
Partnership of Southwest Developmental
Drilling Fund 92-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
No report on Form 8-K was filed 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 92-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 92-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 92-
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 92-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 92-
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 92-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 92-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 92-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 92-A, L.P.