Page 17 of 20
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 PROGRAM 1991-92
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 of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
_________Midland, Texas 79701_________
(Address of principal executive offices)
________(915) 686-9927________
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all 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 _____
The total number of pages contained in this report is 20.
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the note thereto for
the year ended December 31, 2001, which are found in the Registrant's Form
10-K Report for 2001 filed with the Securities and Exchange Commission.
The December 31, 2001 balance sheet included herein has been taken from the
Registrant's 2001 Form 10-K Report. Operating results for the three and
nine month periods ended September 30, 2002 are not necessarily indicative
of the results that may be expected for the full year.
Southwest Developmental Drilling Fund 92-A, L.P.
Balance Sheets
September December
30, 31,
2002 2001
----------- ---------
(unaudited)
Assets
- ------
Current assets:
Cash and cash equivalents $ 31,703 16,508
Receivable from Managing General 27,651 28,977
Partner
--------- ---------
Total current assets 59,354 45,485
--------- ---------
Oil and gas properties - using the
full-
cost method of accounting 1,313,124 1,313,124
Less accumulated depreciation,
depletion and amortization 1,137,240 1,127,240
--------- ---------
Net oil and gas properties 175,884 185,884
--------- ---------
$ 235,238 231,369
========= =========
Liabilities and Partners' Equity
- --------------------------------
Current liability -
Distribution payable $ - 79
--------- ---------
- 79
--------- ---------
Partners' equity:
General partners 29,458 27,924
Limited partners 205,780 203,366
--------- ---------
Total partners' equity 235,238 231,290
--------- ---------
$ 235,238 231,329
========= =========
Southwest Developmental Drilling Fund 92-A, L.P.
Statements of Operations
(unaudited)
Three Months Nine Months Ended
Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
Revenues
- --------
Oil and Gas $ 74,552 66,022 198,967 266,293
Interest 30 129 67 482
Miscellaneous settlement 1,529 - 1,529
------- ------- ------- -
-------
76,111 66,151 200,563 266,775
------- ------- ------- -------
Expenses
- --------
Production 32,673 28,839 88,123 101,574
General and administrative 5,065 3,937 13,492 12,235
Depreciation, depletion and
amortization 3,000 7,000 10,000 19,000
------- ------- ------- -------
40,738 39,776 111,615 132,809
------- ------- ------- -------
Net income $ 35,373 26,375 88,948 133,966
======= ======= ======= =======
Net income allocated to:
Managing General Partner $ 4,221 3,671 10,884 16,826
======= ======= ======= =======
Investor Partners $ 31,152 22,704 78,064 117,140
======= ======= ======= =======
Per limited partner unit $ 22.14 16.14 55.48 83.25
======= ======= ======= =======
Southwest Developmental Drilling Fund 92-A, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
2002 2001
---- ----
Cash flows from operating activities
Cash received from oil and gas sales $ 196,261 294,132
Cash paid to suppliers (97,583
) (119,230
)
Interest received 67 482
Miscellaneous settlement 1,529 -
------- -------
Net cash provided by operating activities 100,274 175,384
------- -------
Cash flows used in financing activities
Distributions to partners (85,079 (180,000
) )
------- -------
Net increase (decrease) in cash and cash 15,195 (4,616)
equivalents
Beginning of period 16,508 26,865
------- -------
End of period $ 31,703 22,249
======= =======
Reconciliation of net income to net cash
provided by operating activities
Net income $ 88,948 133,966
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation, depletion and amortization 10,000 19,000
(Increase) decrease receivables (2,706) 27,839
Increase (decrease) in payables 4,032 (5,421)
------- -------
Net cash provided by operating activities $ 100,274 175,384
======= =======
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 General
Partner Partners
-------- --------
Interest income on capital contributions - 100%
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and offering costs (1) - 100%
Syndication costs - 100%
Amortization of organization costs - 100%
Lease acquisition costs 1% 99%
Gain/loss on property disposition* 11% 89%
Operating and administrative costs*(2) 11% 89%
Depreciation, depletion and amortization
of oil and gas properties - 100%
Intangible drilling and development costs - 100%
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
The interim financial information as of September 30, 2002, and for
the three and nine months ended September 30, 2002, is unaudited.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim
financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments
are of a normal recurring nature. The interim consolidated financial
statements should be read in conjunction with the audited financial
statements for the year ended December 31, 2001.
3. Subsequent Event
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.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 92-A, L.P. (the Partnership) 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, representing 1,407 interests ($1,000 per
interest). 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 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.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing no workovers
to enhance production. The partnership will most likely experience the
historical production decline of approximately 6% per year.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
involved.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
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. For the nine months ended September 30, 2002, the net
capitalized cost did not exceed the estimated present value of oil and gas
reserves.
Under the units of revenue method, the Partnership computes the provision
by multiplying the total unamortized cost of oil and gas properties by an
overall rate determined by dividing (a) oil and gas revenues during the
period by (b) the total future gross oil and gas revenues as estimated by
the Partnership's independent petroleum consultants. It is reasonably
possible that those estimates of anticipated future gross revenues, the
remaining estimated economic life of the product, or both could be changed
significantly in the near term due to the potential fluctuation of oil and
gas prices or production. The depletion estimate would also be affected by
this change.
Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost method
of accounting for its oil and gas properties. The full cost method
subjects companies to quarterly calculations of a "ceiling", or limitation
on the amount of properties that can be capitalized on the balance sheet.
If the Partnership's capitalized costs are in excess of the calculated
ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
Results of Operations
A. General Comparison of the Quarters Ended September 30, 2002 and 2001
The following table provides certain information regarding performance
factors for the quarters ended September 30, 2002 and 2001:
Three Months
Ended Percentage
September 30, Increase
2002 2001 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 26.94 25.43 6%
Average price per mcf of gas $ 2.87 2.78 3%
Oil production in barrels 2,150 2,320 (7%)
Gas production in mcf 5,800 5,000 16%
Gross oil and gas revenue $ 74,552 66,022 13%
Net oil and gas revenue $ 41,879 37,183 13%
Partnership distributions $ 25,000 50,000 (50%)
Investor partner distributions $ 22,250 44,500 (50%)
Per unit distribution to investor partners $ 15.81 31.63 (50%)
Number of investor partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues increased to $74,552 from $66,022
for the quarters ended September 30, 2002 and 2001, respectively, an
increase of 13%. The principal factors affecting the comparison of the
quarters ended September 30, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended September 30, 2002 as compared to
the quarter ended September 30, 2001 by 6%, or $1.51 per barrel,
resulting in an increase of approximately $3,200 in revenues. Oil
sales represented 78% of total oil and gas sales during the quarter
ended September 30, 2002 as compared to 81% during the quarter ended
September 30, 2001.
The average price for an mcf of gas received by the Partnership
increased during the same period by 3%, or $.09 per mcf, resulting in
an increase of approximately $500 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $3,700. 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 170 barrels or 7% during the
quarter ended September 30, 2002 as compared to the quarter ended
September 30, 2001, resulting in a decrease of approximately $4,300 in
revenues.
Gas production increased approximately 800 mcf or 16% during the same
period, resulting in an increase of approximately $2,200 in revenues.
The net total decrease in revenues due to the change in production is
approximately $2,100.
Costs and Expenses
Total costs and expenses increased to $40,738 from $39,776 for the quarters
ended September 30, 2002 and 2001, respectively, an increase of 2%. The
increase is the result of higher lease operating costs and general and
administrative expense, partially offset by a decrease in depletion
expense.
1. Lease operating costs and production taxes were 13% higher, or
approximately $3,800 more during the quarter ended September 30, 2002 as
compared to the quarter ended September 30, 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
29% or approximately $1,100 during the quarter ended September 30, 2002
as compared to the quarter ended September 30, 2001. The increase in
general and administrative costs is predominantly due to an increase in
independent accounting fees.
3. Depletion expense decreased to $3,000 for the quarter ended September
30, 2002 from $7,000 for the same period in 2001. This represents a
decrease of 57%. 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 contributing
factors to the decrease in depletion expense between the comparative
periods were the increase in the price of oil and gas used to determine
the Partnership's reserves for October 1, 2002 as compared to 2001, and
the increase in oil and gas revenues received by the Partnership during
2002 as compared to 2001.
Results of Operations
B. General Comparison of the Nine Month Periods Ended September 30, 2002
and 2001
The following table provides certain information regarding performance
factors for the nine month periods ended September 30, 2002 and 2001:
Nine Months
Ended Percentage
September 30, Increase
2002 2001 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 23.64 26.69 (11%)
Average price per mcf of gas $ 2.71 4.59 (41%)
Oil production in barrels 6,540 7,070 (7%)
Gas production in mcf 16,400 16,900 (3%)
Gross oil and gas revenue $ 198,967 266,293 (25%)
Net oil and gas revenue $ 110,844 164,719 (33%)
Partnership distributions $ 85,000 180,000 (53%)
Investor partner distributions $ 75,650 160,200 (53%)
Per unit distribution to investor partners $ 53.77 113.86 (53%)
Number of investor partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues decreased to $198,967 from $266,293
for the nine months ended September 30, 2002 and 2001, respectively, a
decrease of 25%. The principal factors affecting the comparison of the
nine months ended September 30, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the nine months ended September 30, 2002 as compared
to the nine months ended September 30, 2001 by 11%, or $3.05 per
barrel, resulting in a decrease of approximately $19,900 in revenues.
Oil sales represented 78% of total oil and gas sales during the nine
months ended September 30, 2002 as compared to 71% during the nine
months ended September 30, 2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 41%, or $1.88 per mcf, resulting in
a decrease of approximately $30,800 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $50,700. 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 530 barrels or 7% during the
nine months ended September 30, 2002 as compared to the nine months
ended September 30, 2001, resulting in a decrease of approximately
$14,100 in revenues.
Gas production decreased approximately 500 mcf or 3% during the same
period, resulting in a decrease of approximately $2,300 in revenues.
The total decrease in revenues due to the change in production is
approximately $16,400.
Costs and Expenses
Total costs and expenses decreased to $111,615 from $132,809 for the nine
months ended September 30, 2002 and 2001, respectively, a decrease of 16%.
The decrease is the result of lower lease operating costs and depletion
expense, partially offset by an increase in general and administrative
expense.
1. Lease operating costs and production taxes were 13% lower, or
approximately $13,500 less during the nine months ended September 30,
2002 as compared to the nine months ended September 30, 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
10% or approximately $1,300 during the nine months ended September 30,
2002 as compared to the nine months ended September 30, 2001.
3. Depletion expense decreased to $10,000 for the nine months ended
September 30, 2002 from $19,000 for the same period in 2001. This
represents a decrease of 47%. 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
contributing factors to the decrease in depletion expense between the
comparative periods were the increase in the price of oil and gas used
to determine the Partnership's reserves for October 1, 2002 as compared
to 2001, and the decrease in oil and gas revenues received by the
Partnership during 2002 as compared to 2001.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $100,300 in
the nine months ended September 30, 2002 as compared to approximately
$175,400 in the nine months ended September 30, 2001. The primary source
of the 2002 cash flow from operating activities was profitable operations.
Cash flows used in financing activities were approximately $85,100 in the
nine months ended September 30, 2002 as compared to approximately $180,000
in the nine months ended September 30, 2001. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 2002 were
$85,000 of which $75,650 was distributed to the investor partners and
$9,350 to the Managing General Partner. The per unit distribution to
investor partners during the nine months ended September 30, 2002 was
$53.77. Total distributions during the nine months ended September 30,
2001 were $180,000 of which $160,200 was distributed to the investor
partners and $19,800 to the Managing General Partner. The per unit
distribution to investor partners during the nine months ended September
30, 2001 was $113.86.
The source for the 2002 distributions of $85,000 was oil and gas operations
of approximately $100,300, resulting in excess cash for contingencies or
subsequent distributions. The sources for the 2001 distributions of
$180,000 were oil and gas operations of approximately $175,400, with the
balance from available cash on hand at the beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,671,353 have been made to the partners. As of September 30, 2002,
$1,487,880 or $1,057.48 per investor partner unit has been distributed to
the investor partners, representing a 106% return of the capital
contributed.
As of September 30, 2002, the Partnership had approximately $59,400 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenues generated from operations
are adequate to meet the needs of the Partnership.
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.
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.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets." This pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed" and eliminates the requirement of
Statement 121 to allocate goodwill to long-lived assets to be tested for
impairment. The provisions of this statement are effective for financial
statements issued for fiscal years beginning after December 15, 2001, and
interim periods within those fiscal years. The Managing General Partner
believes that the impact from SFAS No. 144 on the Partnerships financial
position and results of operation should not be significantly different
from that of SFAS No. 121.
In April 2002, FASB issued SFAS No. 145, "Rescission of SFAS No. 4, 44, and
64, Amendment of SFAS No. 13, and Technical Corrections." This Statement
rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt", and an amendment of that Statement, SFAS No. 64, "Extinguishments of
Debt Made to Satisfy Sinking-Fund Requirements". This Statement also
rescinds or amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their
applicability under changed conditions. This standard is effective for
fiscal years beginning after May 15, 2002. The Managing General Partner
believes that the adoption of this statement will not have a significant
impact on the Partnerships financial statements.
In July 2002, FASB issued SFAS No. 146 "Accounting for Costs Associated
with Exit or Disposal Activities" which establishes requirements for
financial accounting and reporting for costs associated with exit or
disposal activities. This standard is effective for exit or disposal
activities initiated after December 31, 2002. The Managing General Partner
is currently assessing the impact of this statement on the Partnerships'
future financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures. The chief
executive officer and chief financial officer of the Partnership's managing
general partner have evaluated the effectiveness of the design and
operation of the Partnership's disclosure controls and procedures (as
defined in Exchange Act Rule 13a-14(c)) as of a date within 90 days of the
filing date of this quarterly report. Based on that evaluation, the chief
executive officer and chief financial officer have concluded that the
Partnership's disclosure controls and procedures are effective to ensure
that material information relating to the Partnership and the Partnership's
consolidated subsidiaries is made known to such officers by others within
these entities, particularly during the period this quarterly report was
prepared, in order to allow timely decisions regarding required disclosure.
(b) Changes in Internal Controls. There have not been any significant
changes in the Partnership's internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) No reports on Form 8-K were filed during the quarter for
which this report is filed.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant 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/ Bill E. Coggin
------------------------------
Bill E. Coggin, Executive Vice
President
and Chief Financial Officer
Date: November 14, 2002
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q of
Southwest Developmental Drilling Fund 92-A, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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 quarterly 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 quarterly 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 quarterly report (the "Evaluation Date"); and
c) presented in this quarterly 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 quarterly report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 92-A, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form 10-Q of
Southwest Developmental Drilling Fund 92-A, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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 quarterly 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 quarterly 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 quarterly report (the "Evaluation Date"); and
c) presented in this quarterly 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 quarterly report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/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.