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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, 2002
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number 33-38511
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 (915) 686-9927
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
limited 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 (229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [x]
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of Aggregate market value.
The total number of pages contained in this report is 41. The exhibit
index is found on page 39.
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 5
3. Legal Proceedings 6
4. Submission of Matters to a Vote of Security Holders 6
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 7
6. Selected Financial Data 8
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 9
8. Financial Statements and Supplementary Data 16
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 30
Part III
10. Directors and Executive Officers of the Registrant 31
11. Executive Compensation 33
12. Security Ownership of Certain Beneficial Owners and
Management 33
13. Certain Relationships and Related Transactions 34
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 35
Signatures 36
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 82 individuals, together with certain
independent consultants used on an "as needed" basis, perform various
services on behalf of the Partnership, including the selection of leasehold
interests upon which drilling would be performed, and the marketing of
future anticipated production from such properties. The Partnership has no
employees.
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.
In 2002, fighting and threats of fighting in the Middle East and a strike
in a major oil exporting country dominated the direction of crude oil
prices. While OPEC agreed to keep production constant throughout the year,
conflicts between the U.S. and Iraq, as well as between Israel and the
Palestinians threatened supplies and caused oil prices to surge in 2002.
In addition, a strike by oil workers in Venezuela, the fourth largest
supplier to the U.S., took a siginifcant amount of crude oil off the market
toward the end of the year. As a result, OPEC agreed in January 2003 to
increase output by 1.5 million barrels per day in an effort to make up for
the lost supply and stabilize prices.
In 2002, spot prices for natural gas fell by 27.5% from the unprecedented
heights reached in 2001, averaging just under $3.00/MMBtu for the year.
Most of the lowest prices were seen early on, with the first quarter
averaging of $2.24/MMBtu. But as the year progressed, prices climbed
higher, ending with a $3.99 average in December. As for 2003, industry
analysts are divided on their gas price predictions, with estimates ranging
anywhere from $4.00 to $6.00/MMBtu. Weather forecasts, storage inventory
levels, a tighter supply and demand balance, and the unstable situation
with Iraq are all factors that will have a significant impact on the
direction prices will take. Overall however, analysts are maintaining a
bullish perspective, expecting gas prices to remain at or above $4.00/MMBtu
in 2003.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
---- ----
2002 75% 25%
2001 72% 28%
2000 78% 22%
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 is highly seasonal, with higher demand
in the colder winter months and in very hot summer months, the Partnership
anticipates that it will be able to sell all of the expected future
production of natural gas, either through contracts 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
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%. Three purchasers accounted for 94% of the Partnership's
total oil and gas production during 2000: Plains Marketing LP for 63%,
Navajo Refining Company, Inc. for 16% and Duke Energy Transport and Trad.
for 15%. 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. Moreover, certain prices at,
which the Partnership may sell its future expected natural gas production,
are controlled by the Natural Gas Policy Act of 1978, the Natural Gas
Wellhead Decontrol Act of 1989 and the regulations promulgated by the
Federal Energy Regulatory Commission.
Environmental - The Partnership's oil and gas activities are subject to
extensive federal, state and local laws and regulations governing the
generation, storage, handling, emission, transportation and discharge of
materials into the environment. Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties. This regulatory burden on the oil and gas industry increases
its cost of doing business and consequently affects its profitability. The
Managing General Partner is unable to predict what, if any, effect
compliance will have on the Partnership.
Industry Regulations and Guidelines - Certain industry regulations and
guidelines apply to the registration, qualification and operation of oil
and gas programs in the form of limited partnerships. The Partnership is
subject to these guidelines, which regulate and restrict transactions
between the Managing General Partner and the Partnership. The Partnership
complies with these guidelines and the Managing General Partner does not
anticipate that continued compliance will have a material adverse effect on
Partnership operations.
Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a staff of geologists, engineers, accountants, landmen and clerical staff
who engage in Partnership activities and operations and perform additional
services for the Partnership as needed. In addition to the Managing
General Partner's staff, the Partnership engages independent consultants
such as petroleum engineers and geologists as needed. As of December 31,
2002, there were 82 individuals directly employed by the Managing General
Partner in various capacities.
Item 2. Properties
In determining whether an interest in a particular 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, 2002, 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 2002, 2001
and 2000.
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 28,000 24,000
#1
Ward County, 100%
Texas
working
interest
Mobil Fee H 12/92 at 1 45,000 167,000
#1
Ward County, 100%
Texas
working
interest
*Ryder Scott Company, L.P. prepared the reserve and present value data for
the Partnership's existing properties as of January 1, 2003. The reserve
estimates were made in accordance with guidelines established by the
Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-
X. Such guidelines require oil and gas reserve reports be prepared under
existing economic and operating conditions with no provisions for price and
cost escalation except by contractual arrangements.
Oil price adjustments were made in the individual evaluations to reflect
oil quality, gathering and transportation costs. The results of the reserve
report as of January 1, 2003 are an average price of $29.67 per barrel.
Gas price adjustments were made in the individual evaluations to reflect
BTU content, gathering and transportation costs and gas processing and
shrinkage. The results of the reserve report as of January 1, 2003 are an
average price of $4.49 per Mcf.
As also discussed in Part II, Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations, oil and gas prices were
subject to frequent changes in 2002.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly with
respect to the quantity of oil or gas that any given property is capable of
producing. Estimates of oil and gas reserves are based on available
geological and engineering data, the extent and quality of which may vary
in each case and, in certain instances, may prove to be inaccurate.
Consequently, properties may be depleted more rapidly than the geological
and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than
previously estimated; thus an ultimately lower return for the Partnership.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is available
during the subsequent year evaluation. In applying industry standards and
procedures, the new data may cause the previous estimates to be revised.
This revision may increase or decrease the earlier estimated volumes.
Pertinent information gathered during the year may include actual
production and decline rates, production from offset wells drilled to the
same geologic formation, increased or decreased water production,
workovers, and changes in lifting costs, among others. Accordingly,
reserve estimates are often different from the quantities of oil and gas
that are ultimately recovered.
The Partnership has reserves, which are classified as proved developed
producing. All of the proved reserves are included in the engineering
reports, which evaluate the Partnership's present reserves.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth
quarter of 2002 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
Market Information
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, 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. As of
December 31, 2002, no limited partner units were purchased by the Managing
General Partner. Southwest, as Managing General Partner, evaluated several
liquidity alternatives for the partnerships in 2001 and 2002. During 2002,
Southwest specifically pursued the possible roll-up and merger of twenty-
one (21) partnerships with the general partner. Because of the
complexities and conflicts of interest in such a transaction, the Managing
General Partner did not make a formal repurchase offer in 2002 but has
responded to limited partners desiring to sell their units in the
partnerships on an "as requested" basis. Southwest anticipates that it
will maintain this policy in 2003 because the aforementioned transaction is
ongoing. As of December 31, 2001, no limited partner units were purchased
by the Managing General Partner. In 2000, 5 limited partner units were
tendered to and purchased by the Managing General Partner at an average
base price of $181.86 per unit.
Number of Limited and General Partner Interest Holders
As of December 31, 2002, 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 2002, quarterly 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, quarterly 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. During 2000, quarterly
distributions were made totaling $224,640, with $199,930 distributed to the
investor partners and $24,710 to the Managing General Partners. For the
year ended December 31, 2000, distributions of $142.10 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, 2002,
2001, 2000, 1999 and 1998 should be read in conjunction with the financial
statements included in Item 8:
Year ended December 31,
---------------------------------------------
---
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Revenues $ 275,362 333,192 372,553 249,965 201,370
Net income (loss) 120,581 160,893 217,640 112,767 (331,847
)
Partners' share of
net
income (loss):
Managing General
Partner 14,804 20,338 25,590 14,274 6,863
Investor partners 105,777 140,555 192,050 98,493 (338,710
)
Investor partners'
net
income (loss) per 75.18
unit 99.90 136.50 70.00 (240.73)
Investor partners'
cash
distributions per 71.45
unit 132.08 142.10 53.77 58.32
Total assets $ 238,993 231,369 279,195 286,195 258,508
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 have approximated 7% per year.
Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost method
of accounting for its oil and gas properties. The full cost method
subjects companies to quarterly calculations of a "ceiling", or limitation
on the amount of properties that can be capitalized on the balance sheet.
If the Partnership's capitalized costs are in excess of the calculated
ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
Prior to October 1, 2002, the Partnership calculated depletion of oil and
gas properties under the units of revenue method. The Partnership changed
methods of estimating depletion effective October 1, 2002 to the units of
production method. The units of production method is more predominantly
used throughout the oil and gas industry and will allow the Partnership to
more closely align itself with its peers. This change in estimate had no
impact on depletion expense for the fourth quarter.
Results of Operations
A. General Comparison of the Years Ended December 31, 2002 and 2001
The following table provides certain information regarding performance
factors for the years ended December 31, 2002 and 2001:
Year Ended Percenta
ge
December 31, Increase
2002 2001 (Decreas
e)
---- ---- --------
-
Average price per $ 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%)
Gross oil and gas $ 273,741 332,643 (18%)
revenue
Net oil and gas $ 150,469 200,862 (25%)
revenue
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.
1. 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%. Prior to October 1, 2002, the Partnership calculated
depletion of oil and gas properties under the units of revenue method.
The Partnership changed methods of estimating depletion effective
October 1, 2002 to the units of production method. The units of
production method is more predominantly used throughout the oil and gas
industry and will allow the Partnership to more closely align itself
with its peers. This change in estimate had no impact on depletion
expense for the fourth quarter.
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, and the decrease in oil and gas revenues received by the
Partnership during 2002 as compared to 2001.
Results of Operations
B. General Comparison of the Years Ended December 31, 2001 and 2000
The following table provides certain information regarding performance
factors for the years ended December 31, 2001 and 2000:
Year Ended Percenta
ge
December 31, Increase
2001 2000 (Decreas
e)
---- ---- --------
-
Average price per $ 25.25 (15%)
barrel of oil 29.73
Average price per mcf $ 4.08 3%
of gas 3.98
Oil production in 9,460 9,800 (3%)
barrels
Gas production in mcf 23,000 20,200 14%
Gross oil and gas $ 332,643 371,824 (11%)
revenue
Net oil and gas revenue $ 200,862 247,853 (19%)
Partnership $ 208,798 224,640 (7%)
distributions
Limited partner $ 185,830 199,930 (7%)
distributions
Per unit distribution $ 132.08 (7%)
to limited partners 142.10
Number of limited 1,407 1,407
partner units
Revenues
The Partnership's oil and gas revenues decreased to $332,643 from $371,824
for the years ended December 31, 2001 and 2000, respectively, a decrease of
11%. The principal factors affecting the comparison of the years ended
December 31, 2001 and 2000 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 2001 as compared to the
year ended December 31, 2000 by 15%, or $4.48 per barrel, resulting in
a decrease of approximately $42,400 in revenues. Oil sales represented
72% of total oil and gas sales during the year ended December 31, 2001
as compared to 78% during the year ended December 31, 2000.
The average price for an mcf of gas received by the Partnership
increased during the same period by 3%, or $.10 per mcf, resulting in
an increase of approximately $2,300 in revenues.
The net total decrease in revenues due to the change in prices received
from oil and gas production is approximately $40,100. The market price
for oil and gas has been extremely volatile over the past decade and
management expects a certain amount of volatility to continue in the
foreseeable future.
2. Oil production decreased approximately 340 barrels or 3% during the
year ended December 31, 2001 as compared to the year ended December 31,
2000, resulting in a decrease of approximately $10,100 in revenues.
Gas production increased approximately 2,800 mcf or 14% during the same
period, resulting in an increase of approximately $11,100 in revenues.
The net total increase in revenues due to the change in production is
approximately $1,000.
Costs and Expenses
Total costs and expenses increased to $172,299 from $154,913 for the years
ended December 31, 2001 and 2000, respectively, an increase of 11%. The
increase is the result of higher lease operating costs, depletion expense
and general and administrative expense.
1.Lease operating costs and production taxes were 6% higher, or
approximately $7,800 more during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
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 4%
or approximately $600 during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
3. Depletion expense increased to $24,000 for the year ended December 31,
2001 from $15,000 for the same period in 2000. This represents an
increase of 60%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants.
The major factor in the increase in depletion expense between the
comparative periods was the decrease in the price of oil and gas used
to determine the Partnership's reserves for January 1, 2002 as compared
to 2001, and the decrease in oil and gas revenues received by the
Partnership during 2001 as compared to 2000. Revisions of previous
estimates can be attributed to the changes in production performance,
oil and gas price and production costs. The impact of the revision
would have increased depletion expense approximately $6,000 as of
December 31, 2000.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2002, 2001 and 2000
was $120,581, $160,893 and $217,640, respectively. Excluding the effects
of depreciation, depletion and amortization, net income for the years ended
December 31, 2002, 2001 and 2000, would have been $134,581, $184,893 and
$232,640, respectively. Correspondingly, Partnership distributions for the
years ended December 31, 2002, 2001 and 2000 were $112,957, $208,798 and
$224,640, respectively. These differences are indicative of the changes in
oil and gas prices, production and property during 2002, 2001 and 2000.
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. The sources for the 2000 distributions of $224,640 were oil and
gas operations of approximately $228,800 and the change in oil and gas
properties of approximately $(75), resulting in excess cash for
contingencies or subsequent distributions.
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. Total distributions during the year ended December 31,
2000 were $224,640 of which $199,930 was distributed to the investor
partners and $24,710 to the Managing General Partners. The per unit
distribution to investor partners during the same period was $142.10.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,699,310 have been made to the partners. As of December 31, 2002,
$1,512,762 or $1,075.17 per investor partner unit, has been distributed to
the investor partners, representing a 100% return of capital and a 8%
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 $124,000 in
2002 compared to $197,000 in 2001 and approximately $228,800 in 2000. The
primary source of the 2002 cash flow from operating activities was
profitable operations.
Cash flows (used in) provided by investing activities were approximately
$(10) in 2002 compared to $1,400 in 2001 and approximately $(75) in 2000.
The primary use of the 2002 cash flow from investing activities was the
change in oil and gas properties.
Cash flows used in financing activities were approximately $113,000 in 2002
compared to $208,700 in 2001 and approximately $224,600 in 2000. The only
use in the 2002 financing activities was the distributions to partners.
As of December 31, 2002, the Partnership had $67,000 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 Managing General Partner anticipates that at
some point in the near future, the partnership will need to be liquidated.
Maintenance of properties and administrative expenses are increasing
relative to production. As the properties continue to deplete, maintenance
of properties and administrative costs as a percentage of production will
continue to increase.
As the partnerships properties have matured, the net cash flows from
operations for the partnership have generally declined, except in periods
of substantially increased commodity pricing. Since the partnership cannot
develop their non-producing properties, the producing reserves continue to
deplete causing cash flow to steadily decline.
On October 17, 2002, Southwest Royalties, Inc. the Managing General Partner
filed an S-4 "Registration of Securities, Business Combinations" with the
Securities and Exchange Commission. The S-4 relates to a proposed plan of
merger of twenty-one limited partnerships.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
approximately $124.0 million of principal due between December 31, 2002 and
December 31, 2004. The Managing General Partner is constantly monitoring
its cash position and its ability to meet its financial obligations as they
become due, and in this effort, is continually exploring various strategies
for addressing its current and future liquidity needs. The Managing
General Partner regularly pursues and evaluates recapitalization strategies
and acquisition opportunities (including opportunities to engage in
mergers, consolidations or other business combinations) and at any given
time may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to fund
debt service, developmental projects and day to day operations, but it is
not sufficient to build a cash balance which would allow the Managing
General Partner to meet its debt principal maturities scheduled for 2004.
Therefore the Managing General Partner must renegotiate the terms of its
various obligations or seek new lenders or equity investors in order to
meet its financial obligations, specifically those maturing in 2004. The
Managing General Partner may be required to dispose of certain assets in
order to meet its obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the debt holders will
agree to a course of action consistent with the Managing General Partner's
requirements in restructurings the obligations. Furthermore, there can be
no assurance that the sales of assets can be successfully accomplished on
terms acceptable to the Managing General Partner.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged. The Managing General Partner is currently assessing the impact
on the partnerships financial statements.
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 17
Balance Sheets 18
Statement of Operations 19
Statement of Changes in Partners' Equity 20
Statements of Cash Flows 21
Notes to Financial Statements 22
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, 2002 and 2001,
and the related statements of operations, changes in partners' equity and
cash flows for each of the years in the three year period ended December
31, 2002. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Developmental
Drilling Fund 92-A as of December 31, 2002 and 2001 and the results of its
operations and its cash flows for each of the years in the three year
period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.
KPMG LLP
Midland, Texas
March 14, 2003
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2002 and 2001
2002 2001
---- ----
Assets
- ------
Current assets:
Cash and cash equivalents $ 27,569 16,508
Receivable from Managing 39,532 28,977
General Partner
-------- --------
---- ----
Total current assets 67,101 45,485
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 1,313,13 1,313,12
2 4
Less accumulated
depreciation,
depletion and 1,141,24 1,127,24
amortization 0 0
-------- --------
---- ----
Net oil and gas 171,892 185,884
properties
-------- --------
---- ----
$ 238,993 231,369
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ----
Current liability - $ 79 79
distribution payable
-------- --------
---- ----
Partners' equity:
Managing General Partner 30,303 27,924
Investor partners 208,611 203,366
-------- --------
---- ----
Total partners' equity 238,914 231,290
-------- --------
---- ----
$ 238,993 231,369
======= ========
=
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, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
Revenues
- ------------
Oil and gas sales $ 273,741 332,643 371,824
Interest income from 92 549 729
operations
Miscellaneous 1,529 - -
-------- -------- --------
-- -- --
275,362 333,192 372,553
-------- -------- --------
-- -- --
Expenses
- ------------
Production 123,272 131,781 123,971
General and administrative 17,509 16,518 15,942
Depreciation, depletion and 14,000 24,000 15,000
amortization
-------- -------- --------
-- -- --
154,781 172,299 154,913
-------- -------- --------
-- -- --
Net income $ 120,581 160,893 217,640
====== ====== ======
Net income allocated to:
Managing General Partner $ 14,804 20,338 25,590
====== ====== ======
Investor partners $ 105,777 140,555 192,050
====== ====== ======
Per investor partner unit $ 75.18
99.90 136.50
====== ====== ======
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, 2002, 2001 and 2000
Managing
General Investor
Partner Partners Total
-------- -------- -----
Balance at December 31, 1999 $ 29,674 256,521 286,195
Net income 25,590 192,050 217,640
Distributions (24,710) (199,930 (224,640
) )
-------- -------- --------
-- --- ---
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 14,804 105,777 120,581
Distributions (12,425) (100,532 (112,957
) )
-------- -------- --------
-- --- ---
Balance at December 31, 2002 $ 30,303 208,611 238,914
====== ====== ======
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, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
Cash flows from operating
activities:
Cash received from oil and $ 257,856 353,274 361,584
gas sales
Cash paid to Managing
General Partner
for administrative fees
and general
and administrative (135,451 (156,854 (133,476
overhead ) ) )
Interest received 92 549 729
Miscellaneous settlement 1,529 - -
-------- -------- --------
-- -- --
Net cash provided by 124,026 196,969 228,837
operating activities
-------- -------- --------
-- -- --
Cash flows from investing
activities:
Addition to oil and gas (8) - (75)
properties
Sale of equipment - 1,393 -
-------- -------- --------
-- -- --
Net cash (used in)
provided by
investing activities (8) 1,393 (75)
-------- -------- --------
-- -- --
Cash flows used in financing
activities:
Distributions to partners (112,957 (208,719 (224,640
) ) )
-------- -------- --------
-- -- --
Net increase (decrease) in
cash and cash
equivalents 11,061 (10,357) 4,122
Beginning of period 16,508 26,865 22,743
-------- -------- --------
-- -- --
End of period $ 27,569 16,508 26,865
====== ====== ======
Reconciliation of net income
to net
cash provided by operating
activities:
Net income $ 120,581 160,893 217,640
Adjustments to reconcile net
income to
net cash provided by
operating activities:
Depreciation, depletion and 14,000 24,000 15,000
amortization
(Increase) decrease in (15,885) 20,631 (10,240)
receivables
Increase (decrease) in 5,330 (8,555) 6,437
payables
-------- -------- --------
-- -- --
Net cash provided by $ 124,026 196,969 228,837
operating activities
====== ====== ======
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.
Prior to October 1, 2002, the Partnership calculated depletion of oil
and gas properties under the units of revenue method. The Partnership
changed methods of estimating depletion effective October 1, 2002 to
the units of production method. The units of production method is
more predominantly used throughout the oil and gas industry and will
allow the Partnership to more closely align itself with its peers.
This change in estimate had no impact on depletion expense for the
fourth quarter.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Oil and Gas Properties - continued
Should the net capitalized costs exceed the estimated present value of
oil and gas reserves, discounted at 10%, such excess costs would be
charged to current expense. In applying the units of revenue method
for the years ended December 31, 2001, 2000 and for the nine months
ended September 30, 2002, we have not excluded royalty and net profit
interest payments from gross revenues as all of our royalty and net
profit interests have been purchased and capitalized to the depletion
basis of our proved oil and gas properties. As of December 31, 2002,
2001 and 2000, the net capitalized costs did not exceed the estimated
present value of oil and gas reserves.
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, 2002, 2001 and 2000, 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,
2002 and 2001 was $161,628 and $173,234, respectively, less than that
shown on the accompanying Balance Sheets in accordance with generally
accepted accounting principles.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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, 2002, 2001 and 2000, there were 1,407 investor
units outstanding held by 105, 105 and 103 partners.
Concentrations of Credit Risk
The Partnership is subject to credit risk through trade receivables.
Although a substantial portion of its debtors' ability to pay is
dependent upon the oil and gas industry, credit risk is minimized due
to a large customer base. All partnership revenues are received by
the Managing General Partner and subsequently remitted to the
partnership and all expenses are paid by the Managing General Partner
and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair
value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of
removal-type costs associated with asset retirements. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Managing General Partner is currently
assessing the impact on the partnerships financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure
with approximately $124.0 million of principal due between December
31, 2002 and December 31, 2004. The Managing General Partner is
constantly monitoring its cash position and its ability to meet its
financial obligations as they become due, and in this effort, is
continually exploring various strategies for addressing its current
and future liquidity needs. The Managing General Partner regularly
pursues and evaluates recapitalization strategies and acquisition
opportunities (including opportunities to engage in mergers,
consolidations or other business combinations) and at any given time
may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to
fund debt service, developmental projects and day to day operations,
but it is not sufficient to build a cash balance which would allow the
Managing General Partner to meet its debt principal maturities
scheduled for 2004. Therefore the Managing General Partner must
renegotiate the terms of its various obligations or seek new lenders
or equity investors in order to meet its financial obligations,
specifically those maturing in 2004. The Managing General Partner
would also consider disposing of certain assets in order to meet its
obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the debt holders will
agree to a course of action consistent with the Managing General
Partner's requirements in restructurings the obligations.
Furthermore, there can be no assurance that the sales of assets can be
successfully accomplished on terms acceptable to the Managing General
Partner.
4. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
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.
Southwest, as Managing General Partner, evaluated several liquidity
alternatives for the partnerships in 2001 and 2002. During 2002,
Southwest specifically pursued the possible roll-up and merger of
twenty-one (21) partnerships with the general partner. Because of the
complexities and conflicts of interest in such a transaction, the
Managing General Partner did not make a formal repurchase offer in
2002 but has responded to limited partners desiring to sell their
units in the partnerships on an "as requested" basis. Southwest
anticipates that it will maintain this policy in 2003 because the
aforementioned transaction is ongoing.
The Partnership is subject to various federal, state and local
environmental laws and regulations, which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 2002, the Partnership has not been fined, cited or
notified of any environmental violations and management is not aware
of any unasserted violations, which would have a material adverse
effect upon capital expenditures, earnings or the competitive position
in the oil and gas industry.
However, the Managing General Partner does recognize by the very
nature of its business, material costs could be incurred in the near
term to bring the Partnership into total compliance. The amount of
such future expenditures is not reliably determinable due to several
factors, including the unknown magnitude of possible contaminations,
the unknown timing and extent of the corrective actions which may be
required, the determination of the Partnership's liability in
proportion to other responsible parties and the extent to which such
expenditures are recoverable from insurance or indemnifications from
prior owners of Partnership's properties.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As provided for in the operating agreement
for each respective oil and gas property in which the Partnership has
an interest, the operator is paid an amount for administrative
overhead attributable to operating such properties, with such amounts
to Southwest Royalties, Inc. as operator approximating $23,700,
$23,600 and $22,700 for the years ended December 31, 2002, 2001 and
2000, respectively. The amounts for administrative overhead
attributable to operating the partnership properties have been
deducted from gross oil and gas revenues in the determination of net
profit interest. In addition, the Managing General Partner and
certain officers and employees may have an interest in some of the
properties that the Partnership also participates.
Certain subsidiaries or affiliates of the Managing General Partner
perform various oilfield services for properties in which the
Partnership owns an interest. Such services aggregated approximately
$0, $500 and $3,700 for the years ended December 31, 2002, 2001 and
2000, respectively. The amounts for oilfield services performed for
the partnership by affiliates of the Managing General Partner have
been deducted from gross oil and gas revenues in the determination of
net profit interest
Southwest Royalties, Inc., the Managing General Partner, was paid an
administrative fee of $12,000 during 2002, 2001 and 2000 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 $39,500 and $29,000 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2002 and 2001, respectively.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchaser, where the loss of one would
have a material adverse impact on the Partnership. 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 for19% 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%. Three purchasers
accounted for 94% of the Partnership's total oil and gas production
during 2000: Plains Marketing LP for 63%, Navajo Refining Company,
Inc. for 16% and Duke Energy Transport and Trad. for 15%. 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.
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil Gas
(bbls) (mcf)
-------- --------
-- -
Proved developed and
undeveloped reserves -
January 1, 2000 109,000 309,000
Production (10,000) (20,000)
Revisions of estimates in 11,000 (47,000)
place
-------- --------
-- --
December 31, 2000 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
====== ======
Proved developed reserves -
December 31, 2000 110,000 242,000
====== ======
December 31, 2001 79,000 245,000
====== ======
December 31, 2002 88,000 236,000
====== ======
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
7. 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, 2003. The
reserve estimates were made in accordance with guidelines established
by the Securities and Exchange Commission pursuant to Rule 4-10(a) of
Regulation S-X. Such guidelines require oil and gas reserve reports
be prepared under existing economic and operating conditions with no
provisions for price and cost escalation except by contractual
arrangements.
Oil price adjustments were made in the individual evaluations to
reflect oil quality, gathering and transportation costs. The results
of the reserve report as of January 1, 2003 are an average price of
$29.67 per barrel.
Gas price adjustments were made in the individual evaluations to
reflect BTU content, gathering and transportation costs and gas
processing and shrinkage. The results of the reserve report as of
January 1, 2003 are an average price of $4.49 per Mcf.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. As new data is gathered during the subsequent year, the
engineer must revise his earlier estimates. A year of new information,
which is pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves, which are classified as proved developed
producing. 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
7. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2002, 2001 and 2000 is
presented below:
2002 2001 2000
---- ---- ----
Future cash inflows $ 3,682,00 2,059,00 5,290,00
0 0 0
Production and development 1,945,00 1,334,00 2,403,00
costs 0 0 0
-------- -------- --------
---- ---- ----
Future net cash flows 1,737,00 725,000 2,887,00
0 0
10% annual discount for
estimated
timing of cash flows 680,000 260,000 1,309,00
0
-------- -------- --------
---- ---- ----
Standardized measure of
discounted
future net cash flows $ 1,057,00 465,000 1,578,00
0 0
======= ======= =======
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2002, 2001 and 2000 are as follows:
2002 2001 2000
---- ---- ----
Sales of oil and gas
produced,
net of production costs $ (150,000 (201,000 (248,000
) ) )
Changes in prices and 549,000 (1,178,0 866,000
production costs 00)
Changes of production rates
(timing) and others (12,000) 177,000 (49,000)
Revisions of previous
quantities estimates 159,000 (69,000) 33,000
Accretion of discount 46,000 158,000 89,000
Discounted future net
cash flows -
Beginning of year 465,000 1,578,00 887,000
0
-------- -------- --------
---- ---- ----
End of year $ 1,057,00 465,000 1,578,00
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
8. Selected Quarterly Financial Results - (unaudited)
Quarter
--------------------------------------
--------
First Second Third Fourth
------ ------- ------ ------
2002:
Total revenues $ 53,515 70,937 76,111 74,799
Total expenses 36,583 34,294 40,738 43,166
Net income 16,932 36,643 35,373 31,633
Net income per limited
partners unit 10.48
22.87 22.14 19.69
2001:
Total revenues $ 124,995 75,628 66,151 66,418
Total expenses 43,013 50,019 39,776 39,491
Net income 81,982 25,609 26,375 26,927
Net income per limited
partners unit 51.31
15.81 16.14 16.64
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None
Part III
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as
Managing General Partner. The names, ages, offices, positions and length
of service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below. Each director and executive officer serves for a
term of one year.
Name Age Position
H. H. Wommack, III 47 Chairman of the Board,
President, Director
and Chief Executive Officer
James N. Chapman(1) 40 Director
William P. Nicoletti(2) 57 Director
Joseph J. Radecki, Jr. 44 Director
(2)
Richard D. Rinehart(1) 67 Director
John M. White(2) 46 Director
Herbert C. Williamson, 54 Director
III(1)
Bill E. Coggin 48 Executive Vice President and
Chief Financial Officer
J. Steven Person 44 Vice President, Marketing
(1) Member of the Compensation Committee
(2) Member of the Audit Committee
H. H. Wommack, III has served as Chairman of the Board, President, Chief
Executive Officer and a director since Southwest's founding in 1983. Since
1997 Mr. Wommack has served as President, Chief Executive Officer and
Chairman of SRH, Southwest's former parent and current holder of 10% of its
voting share capital. Since 1997 Mr. Wommack has served as chairman of the
board of directors of Midland Red Oak Realty, Inc. 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. Prior to Southwest's formation, Mr. Wommack
was a self-employed independent oil and gas producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases
and the drilling of wells. Mr. Wommack graduated from the University of
North Carolina at Chapel Hill and received his law degree from the
University of Texas.
James N. Chapman has served as a director since April 19, 2002. Mr.
Chapman has been involved in the investment banking industry for 18 years,
presently acting as a capital markets and strategic planning consultant
with private and public companies across a range of industries, including
metals, mining, manufacturing, aerospace, airline, service and healthcare.
Prior to establishing an independent consulting practice, Mr. Chapman
worked for The Renco Group, Inc., a multi-billion private corporation in
New York, for which Mr. Chapman developed and implemented financing and
merger and acquisitions strategies for Renco's diverse portfolio of
companies. Prior to Renco, Mr. Chapman was a founding principal of
Fieldstone Private Capital Group, a capital markets advisory firm that he
joined upon its inception in August 1990. Prior to joining Fieldstone,
Mr. Chapman worked for Bankers Trust Company for six years, most recently
in the BT Securities Capital Markets area. Mr. Chapman received an MBA
degree with distinction from the Amos Tuck School at Dartmouth College and
was elected an Edward Tuck Scholar. He received his BA degree with
distinction magna cum laude, at Dartmouth College, was elected to Phi Beta
Kappa and was a Rufus Choate Scholar.
William P. Nicoletti has served as a director since April 19, 2002. Mr.
Nicoletti is Managing Director of Nicoletti & Company Inc., an investment
banking and financial advisory firm. He was formerly a senior officer and
head of the Energy Investment Banking Groups of E. F. Hutton & Company
Inc., Paine Webber, Incorporated and McDonald Investments Inc. Mr.
Nicoletti is Chairman of the board of directors of Russell-Stanley
Holdings, Inc., a manufacturer and marketer of steel and plastic industrial
containers. He is a director of Mark WestEnergy Partners, L.P., a business
engaged in the gathering and processing of natural gas and the
fractionation and storage of natural gas liquids. Mr. Nicoletti is also a
Director and Chairman of the Audit Committee of Star Gas Partners, L.P.,
the nation's largest retail distributor of home heating oil and a major
retail distributor of propane gas. Mr. Nicoletti is a graduate of Seton
Hall University and received an MBA degree from Columbia University
Graduate School of Business.
Joseph J. Radecki, Jr. has served as a director since April 19, 2002. Mr.
Radecki is currently a Managing Director in the Leveraged Finance Group of
CIBC World Markets where he is principally responsible for the firm's
financial restructuring and distressed situation advisory practice. Prior
to joining CIBC World Markets, Mr. Radecki was an Executive Vice President
and Director of the Financial Restructuring Group of Jefferies & Company,
Inc. from 1990 to 1998. From 1983 until 1990, Mr. Radecki was First Vice
President in the International Capital Markets Group at Drexel Burnham
Lambert, Inc., where he specialized in financial restructurings and
recapitalizations. Over the past fourteen years, Mr. Radecki has been
integrally involved in over 120 transactions totaling nearly $50 billion in
recapitalized securities. Mr. Radeki currently serves as a Director of
Wherehouse Entertainment, Inc., a music and video specialty retailer, and
RBX Corporation, a manufacturer of rubber and plastic foam and other
polymer products. He has previously served as Chairman of the Board of
American Rice, Inc., an international rice miller and marketer, as a member
of the Board of Directors of Service America Corporation, a national food
service management firm, Bucyrus International, Inc., a mining equipment
manufacturer, and ECO-Net, a non-profit engineering related network firm.
Mr. Radecki graduated magna cum laude in 1980 from Georgetown University
with a B.A. in Government.
Richard D. Rinehart has served as a director since April 19, 2002. Mr.
Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel
Resources, Inc. PetroCap, Inc. provides investment and merchant banking
services to a variety of clients active in the oil and gas industry.
Kestrel Resources, Inc. is a privately owned oil and gas operating company.
He served as Director of Coopers & Lybrand's Energy Systems and Services
Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to
joining Coopers & Lybrand, he was chief executive officer/founder of Dawn
Information Resources, Inc., formed in 1986 and acquired by Coopers &
Lybrand in early 1991. Mr. Rinehart served as CEO of Terrapet Energy
Corporation during the period 1982 through 1986. Prior to the formation of
Terrapet in 1982, he was employed as President of the Terrapet Division of
E.I. DuPont de Nemours and Company. Before its acquisition by DuPont, he
served as CEO and President of Terrapet Corp., a privately owned E & P
company. Before the formation of Terrapet Corp. in 1972, he was manager of
supplementary recovery methods and senior evaluation engineer with H. J.
Gruy and Associates, Inc., Dallas, Texas.
John M. White has served as a director since April 19, 2002. Mr. White is
currently an oil and gas analyst with BMO Nesbitt Burns, responsible for
Fixed Income research on oil, gas and energy companies. Prior to joining
BMO Nesbitt Burns in 1998, Mr. White was responsible for Fixed Income
research on the oil and gas industry at John S. Herold, Inc., an
independent oil and gas research and consulting firm. Mr. White's
experience also includes managing a portfolio of oil and gas loans for The
Bank of Nova Scotia, which included independent exploration and production
companies, oil service companies, gas pipelines, gas processors and
refiners. Prior to entering banking, Mr. White was with BP Exploration,
where he worked primarily in exploration and production.
Herbert C. Williamson, III has served as a director since April 19, 2002.
At present, Mr. Williamson is self-employed as a consultant. From March
2001 to March 2002 Mr. Williamson served as an investment banker with
Petrie Parkman & Co. From April 1999 to March 2001 Mr. Williamson served
as chief financial officer and from August 1999 to March 2001 as a director
of Merlon Petroleum Company, a private oil and gas company involved in
exploration and production in Egypt. Mr. Williamson served as executive
vice president, chief financial officer and director of Seven Seas
Petroleum, Inc., a publicly traded oil and gas exploration company, from
March 1998 to April 1999. From 1995 through April 1998, he served as
director in the Investment Banking Department of Credit Suisse First
Boston. Mr. Williamson served as vice chairman and executive vice
president of Parker and Parsley Petroleum Company, a publicly traded oil
and gas exploration company (now Pioneer Natural Resources Company) from
1985 through 1995.
Bill E. Coggin has served as Vice President and Chief Financial Officer
since joining the Managing General Partner in 1985. Previously, Mr. Coggin
was Controller for Rod Ric Corporation, an oil and gas drilling company,
and for C.F. Lawrence & Associates, a large independent oil and gas
operator. Mr. Coggin received a B.S. in Education and a B.A. in Accounting
from Angelo State University.
J. Steven Person has served as Vice President, Marketing since joining the
Managing General Partner in 1989. Mr. Person began in the investment
industry with Dean Witter in 1983. Prior to joining the Managing General
Partner, Mr. Person was a senior wholesaler with Capital Realty, Inc. While
at Capital Realty, he was involved in the syndication of mortgage based
securities through the major brokerage houses. Mr. Person received a
B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist
University.
Key Employees
Jon P. Tate, age 45, has served as Vice President, Land and Assistant
Secretary of the Managing General Partner since 1989. From 1981 to 1989,
Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent
oil and gas company, as land manager. Mr. Tate is a member of the Permian
Basin Landman's Association.
R. Douglas Keathley, age 47, has served as Vice President, Operations of
the Managing General Partner since 1992. Before joining us, Mr. Keathley
worked as a senior drilling engineer for ARCO Oil and Gas Company and in
similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.
In certain instances, the Managing General Partner will engage professional
petroleum consultants and other independent contractors, including
engineers and geologists in connection with property acquisitions,
geological and geophysical analysis, and reservoir engineering. The
Managing General Partner believes that, in addition to its own "in-house"
staff, the utilization of such consultants and independent contractors in
specific instances and on an "as-needed" basis allows for greater
flexibility and greater opportunity to perform its oil and gas activities
more economically and effectively.
Item 11. Executive Compensation
The Partnership does not have any directors or executive officers. The
executive officers of the Managing General Partner do not receive any cash
compensation, bonuses, deferred compensation or compensation pursuant to
any type of plan, from the Partnership. The Managing General Partner
received $12,000 during 2002, 2001 and 2000 as an administrative fee for
reimbursement of indirect general and administrative expenses.
Item 12. Security Ownership of Certain Beneficial Owners and Management
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 5.0 limited partner units, or .32% limited partner interest. The
Managing General Partner total percentage interest ownership in the
Partnership is 11.3%.
No officer or director of the Managing General Partner 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 March 1, 2003.
Amount and
Nature of Percen
t
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------- ---------- ------
-------------- -------------- ------ -----
Limited Partnership Southwest Royalties, Directly .32%
Interest Inc. Owns
Managing General 5.0 Units
Partner
407 N. Big Spring
Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly .32%
Interest Owns
Chairman of the 5.0 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 2002, 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 $23,700 for administrative overhead
attributable to operating such properties during 2002.
Certain subsidiaries or affiliates of the Managing General Partner perform
various oilfield services for properties in which the Partnership owns an
interest. There were no such services for the period ended December 31,
2002.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Independent Auditors Report
Balance Sheet
Statement of 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).
99.1 Certification pursuant to 18 U.S.C. Section 1350
99.2 Certification pursuant to 18 U.S.C. Section 1350
(b) Reports on Form 8-K
No report on Form 8-K was filed during the
quarter ended December 31, 2002.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Partnership has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Southwest 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: March 28, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Partnership and in the capacities and on the dates indicated.
By:/s/ H. H. Wommack, III By: /s/ James N.
Chapman
- --------------------------- ------------------------
- -------------------- -----------------------
H. H. Wommack, III, James N. Chapman,
Chairman of the Board, Director
President, Director and
Chief Executive Officer
Date: March 28, 2003 Date: March 28, 2003
By: /s/ William P. By: /s/ Joseph J.
Nicoletti Radecki, Jr.
- --------------------------- ------------------------
- -------------------- -----------------------
William P. Nicoletti, Joseph J. Radecki, Jr.,
Director Director
Date: March 28, 2003 Date: March 28, 2003
By: /s/ Richard D. By: /s/ John M. White
Rinehart
- --------------------------- ------------------------
- -------------------- -----------------------
Richard D. Rinehart, John M. White, Director
Director
Date: March 28, 2003 Date: March 28, 2003
By: /s/ Herbert C.
Williamson, III
- ---------------------------
- --------------------
Herbert C. Williamson, III,
Director
Date: March 28, 2003
CERTIFICATIONS
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 annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 92-A, L.P.
CERTIFICATIONS
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 annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 92-A, L.P.
Exhibit Index
Item No. Description Page No.
Exhibit 99.1 Certification pursuant to 18 U.S.C. 40
Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Exhibit 99.2 Certification pursuant to 18 U.S.C. 41
Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
CERTIFICATION PURSUANT TO
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest
Developmental Drilling Fund 92-A, Limited Partnership (the
"Company") on Form 10-K for the period ending December 31, 2002
as filed with the Securities and Exchange Commission on the date
hereof (the "Report"), I, H.H. Wommack, III, Chief Executive
Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the
Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and results of
operation of the Company.
Date: March 28, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 92-A, L.P.
CERTIFICATION PURSUANT TO
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Developmental
Drilling Fund 92-A, Limited Partnership (the "Company") on Form
10-K for the period ending December 31, 2002 as filed with the
Securities and Exchange Commission on the date hereof (the
"Report"), I, Bill E. Coggin, Chief Financial Officer of the
Managing General Partner of the Company, certify, pursuant to 18
U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley
Act of 2002, that:
(3) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(4) The information contained in the Report fairly presents, in
all material respects, the financial condition and results of
operation of the Company.
Date: March 28, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 92-A, L.P.