Page 4 of 18
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, 1999
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 18.
<PAGE>
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, 1998 which are found in the Registrant's Form
10-K Report for 1998 filed with the Securities and Exchange Commission.
The December 31, 1998 balance sheet included herein has been taken from the
Registrant's 1998 Form 10-K Report. Operating results for the three and
nine month periods ended September 30, 1999 are not necessarily indicative
of the results that may be expected for the full year.
<PAGE>
Southwest Developmental Drilling Fund 92-A, L.P.
Balance Sheets
September 30, December 31,
1999 1998
------------- ------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ 16,129 7,512
Receivable from Managing General Partner 33,629 7,814
--------- ---------
Total current assets 49,758 15,326
--------- ---------
Oil and gas properties - using the
full cost method of accounting 1,314,434 1,314,422
Less accumulated depreciation,
depletion and amortization 1,083,240 1,071,240
--------- ---------
Net oil and gas properties 231,194 243,182
--------- ---------
$ 280,952 258,508
========= =========
Liabilities and Partners' Equity
Current liability - distribution payable $ 60 80
--------- ---------
Partners' equity
Investor partners 252,351 233,678
Managing General Partner 28,541 24,750
--------- ---------
Total partners' equity 280,892 258,428
--------- ---------
$ 280,952 258,508
========= =========
<PAGE>
Southwest Developmental Drilling Fund 92-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
Revenues
Oil and gas $ 77,213 44,416 172,948 153,445
Interest 82 185 148 487
------ ------- ------- -------
77,295 44,601 173,096 153,932
------ ------- ------- -------
Expenses
Production 34,087 26,240 80,174 84,484
General and administrative 4,087 5,269 13,458 20,681
Depreciation, depletion and
amortization 3,000 2,000 12,000 33,000
Provision for impairment of
oil and gas properties - - - 97,671
------ ------- ------- -------
41,174 33,509 105,632 235,836
------ ------- ------- -------
Net income (loss) $ 36,121 11,092 67,464 (81,904)
====== ======= ======= =======
Net income (loss) allocated to:
Managing General Partner $ 4,303 1,440 8,741 5,364
====== ======= ======= =======
Investor Partners $ 31,818 9,652 58,723 (87,268)
====== ======= ======= =======
Per investor partner unit $ 22.61 6.86 41.74 (62.02)
====== ======= ======= =======
<PAGE>
Southwest Developmental Drilling Fund 92-A, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
1999 1998
---- ----
Cash flows from operating activities
Cash received from oil and gas sales $ 147,267 171,988
Cash paid to suppliers (93,766) (99,790)
Interest income 148 487
------- -------
Net cash provided by operating activities 53,649 72,685
------- -------
Cash flows provided by investing activities
Additions to oil and gas properties (12) (7)
Cash received from sale of oil and gas
property - 1,000
------- -------
Net cash (used in) provided by investing
activities (12) 993
------- -------
Cash flows used in financing activities
Distributions to partners (45,020) (76,169)
------- -------
Net increase (decrease) in cash and cash equivalents 8,617
(2,491)
Beginning of period 7,512 7,887
------- -------
End of period $ 16,129 5,396
======= =======
(continued)
<PAGE>
Southwest Developmental Drilling Fund 92-A, L.P.
Statements of Cash Flows, continued
(unaudited)
Nine Months Ended
September 30,
1999 1998
---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities
Net income (loss) $ 67,464 (81,904)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depreciation, depletion and amortization 12,000 33,000
Provision for impairment of oil and
gas properties - 97,671
(Increase) decrease in receivables (25,681) 18,543
Increase (decrease) in payables (134) 5,375
------- -------
Net cash provided by operating activities $ 53,649 72,685
======= =======
<PAGE>
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, 1999, and for
the three and nine months ended September 30, 1999, 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, 1998.
<PAGE>
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 the Partnership could
possibly experience a normal decline of 5% to 7% a year. There are no
current plans to perform any workovers in the future.
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, 1999, the net
capitalized cost did not exceed the estimated present value of oil and gas
reserves. A return of the oil price environment experienced during the
first two quarters of 1999 would have an adverse affect on the Company's
revenues and operating cash flow. Also, further declines in oil prices
could result in additional decreases in the carrying value of the Company's
oil and gas properties.
<PAGE>
Results of Operations
A. General Comparison of the Quarters Ended September 30, 1999 and 1998
The following table provides certain information regarding performance
factors for the quarters ended September 30, 1999 and 1998:
Three Months
Ended Percentage
September 30, Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 21.06 12.52 68%
Average price per mcf of gas $ 2.53 1.94 30%
Oil production in barrels 2,800 2,400 17%
Gas production in mcf 7,210 7,400 (3%)
Gross oil and gas revenue $ 77,213 44,416 74%
Net oil and gas revenue $ 43,126 18,176 137%
Partnership distributions $ 19,000 20,500 (7%)
Investor partner distributions $ 16,910 18,245 (7%)
Per unit distribution to investor partners $ 12.02 12.97 (7%)
Number of investor partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues increased to $77,213 from $44,416
for the quarters ended September 30, 1999 and 1998, respectively, an
increase of 74%. The principal factors affecting the comparison of the
quarters ended September 30, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended September 30, 1999 as compared to
the quarter ended September 30, 1998 by 68%, or $8.54 per barrel,
resulting in an increase of approximately $20,500 in revenues. Oil
sales represented 76% of total oil and gas sales during the quarter
ended September 30, 1999 as compared to 68% during the quarter ended
September 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 30%, or $.59 per mcf, resulting in
an increase of approximately $4,400 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $24,900. 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.
<PAGE>
2. Oil production increased approximately 400 barrels or 17% during the
quarter ended September 30, 1999 as compared to the quarter ended
September 30, 1998, resulting in an increase of approximately $8,400 in
revenues.
Gas production decreased approximately 190 mcf or 3% during the same
period, resulting in a decrease of approximately $500 in revenues.
The net total increase in revenues due to the change in production is
approximately $7,900.
Costs and Expenses
Total costs and expenses increased to $41,174 from $33,509 for the quarters
ended September 30, 1999 and 1998, respectively, an increase of 23%. The
increase is the result of higher lease operating costs and depletion
expense, partially offset by a decrease in general and administrative
expense.
1. Lease operating costs and production taxes were 30% higher, or
approximately $7,800 more during the quarter ended September 30, 1999 as
compared to the quarter ended September 30, 1998. The increase in lease
operating costs for the third quarter was primarily due to repair and
maintenance.
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 decreased
22% or approximately $1,200 during the quarter ended September 30, 1999
as compared to the quarter ended September 30, 1998. The decrease of
general and administrative costs were in part due to additional
accounting costs incurred in 1998 in relation to the outsourcing of K-1
tax package preparation; a change in auditors requiring opinions from
both the predecessors and successor auditors and a new accounting
pronouncement requiring review by the independent auditors of the 10-
Q's. The Managing General Partner has also made an effort to cut back
on general and administrative costs whenever and wherever possible.
3. Depletion expense increased to $3,000 for the quarter ended September
30, 1999 from $2,000 for the same period in 1998. This represents an
increase of 50%. 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. Contributing
factors to the increase in depletion expense between the comparative
periods were the increase in the price of oil and gas used to value
reserves at October 1, 1999 and the increase in gross oil and gas
revenues.
<PAGE>
Results of Operations
B. General Comparison of the Nine Month Periods Ended September 30, 1999
and 1998
The following table provides certain information regarding performance
factors for the nine month periods ended September 30, 1999 and 1998:
Nine Months
Ended Percentage
September 30, Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 15.85 13.42 18%
Average price per mcf of gas $ 2.23 1.99 12%
Oil production in barrels 8,160 8,400 (3%)
Gas production in mcf 19,510 20,400 (4%)
Gross oil and gas revenue $ 172,948 153,445 13%
Net oil and gas revenue $ 92,774 68,961 35%
Partnership distributions $ 45,000 76,200 (41%)
Investor partner distributions $ 40,050 67,818 (41%)
Per unit distribution to investor partners $ 28.46 48.20 (41%)
Number of investor partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues increased to $172,948 from $153,445
for the nine months ended September 30, 1999 and 1998, respectively, an
increase of 13%. The principal factors affecting the comparison of the
nine months ended September 30, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the nine months ended September 30, 1999 as compared
to the nine months ended September 30, 1998 by 18%, or $2.43 per
barrel, resulting in an increase of approximately $20,400 in revenues.
Oil sales represented 75% of total oil and gas sales during the nine
months ended September 30, 1999 as compared to 74% during the nine
months ended September 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 12%, or $.24 per mcf, resulting in
an increase of approximately $4,900 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $25,300. 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.
<PAGE>
2. Oil production decreased approximately 240 barrels or 3% during the
nine months ended September 30, 1999 as compared to the nine months
ended September 30, 1998, resulting in a decrease of approximately
$3,800 in revenues.
Gas production decreased approximately 890 mcf or 4% during the same
period, resulting in a decrease of approximately $2,000 in revenues.
The total decrease in revenues due to the change in production is
approximately $5,800.
Costs and Expenses
Total costs and expenses decreased to $105,632 from $235,836 for the nine
months ended September 30, 1999 and 1998, respectively, a decrease of 55%.
The decrease is the result of lower general and administrative expense,
lease operating costs and depletion expense.
1. Lease operating costs and production taxes were 5% lower, or
approximately $4,300 less during the nine months ended September 30,
1999 as compared to the nine months ended September 30, 1998.
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 decreased
35% or approximately $7,200 during the nine months ended September 30,
1999 as compared to the nine months ended September 30, 1998. The
decrease of general and administrative costs were in part due to
additional accounting costs incurred in 1998 in relation to the
outsourcing of K-1 tax package preparation; a change in auditors
requiring opinions from both the predecessors and successor auditors
and a new accounting pronouncement requiring review by the independent
auditors of the 10-Q's. The Managing General Partner has also made an
effort to cut back on general and administrative costs whenever and
wherever possible.
3. Depletion expense decreased to $12,000 for the nine months ended
September 30, 1999 from $33,000 for the same period in 1998. This
represents a decrease of 64%. 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.
Contributing factors to the decline 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, 1999 as compared
to 1998.
4. The net capitalized costs for the nine months ended September 30, 1998
exceeded the estimated present value of oil and gas reserves,
discounted at 10% in the amount of $97,671, such excess costs were
charged to current expense. The write-down had the effect of reducing
net income, but did not affect cash flow or partner distributions.
<PAGE>
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 $53,600 in
the nine months ended September 30, 1999 as compared to approximately
$72,700 in the nine months ended September 30, 1998. The primary source of
the 1999 cash flow from operating activities was profitable operations.
Cash flows (used in) or provided by investing activities were approximately
$(12) in the nine months ended September 30, 1999 as compared to $993 in
the nine months ended September 30, 1998. The principle use of the 1999
cash flow from investing activities was the change in oil and gas
properties.
Cash flows used in financing activities were approximately $45,000 in the
nine months ended September 30, 1999 as compared to approximately $76,200
in the nine months ended September 30, 1998. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 1999 were
$45,000 of which $40,050 was distributed to the investor partners and
$4,950 to the Managing General Partner. The per unit distribution to
investor partners during the nine months ended September 30, 1999 was
$28.46. Total distributions during the nine months ended September 30,
1998 were $76,200 of which $67,818 was distributed to the investor partners
and $8,382 to the Managing General Partner. The per unit distribution to
investor partners during the nine months ended September 30, 1998 was
$48.20.
The sources for the 1999 distributions of $45,000 were oil and gas
operations of approximately $53,600 and the change in oil and gas
properties of approximately $(12), resulting in excess cash for
contingencies or subsequent distributions. The source for the 1998
distributions of $76,200 was oil and gas operations of approximately
$72,700 and the change in oil and gas properties of approximately $1,000,
with the balance from available cash on hand at the beginning of the
period.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,112,915 have been made to the partners. As of September 30, 1999,
$990,870 or $704.24 per investor partner unit has been distributed to the
investor partners, representing a 70% return of the capital contributed.
As of September 30, 1999, the Partnership had approximately $49,700 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.
<PAGE>
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
over $21.0 million of interest payments due within the next twelve months
on its debt obligations. Due to the severely depressed commodity prices
experienced for the past eighteen months, the Managing General Partner is
experiencing difficulty in generating sufficient cash flow to meet its
obligations and sustain its operations. The Managing General Partner is
currently in the process of renegotiating the terms of its various
obligations with its creditors and/or attempting to seek new lenders or
equity investors. Additionally, the Managing General Partner would
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 lenders will agree to
a course of action consistent with the Managing General Partners
requirements in restructuring the obligations. Even if such agreement is
reached, it may require approval of additional lenders, which is not
assured. Furthermore, there can be no assurance that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Under current circumstances, the Managing General
Partner's ability to continue as a going concern depends upon its ability
to (1) successfully restructure its obligations or obtain additional
financing as may be required, (2) maintain compliance with all debt
covenants, (3) generate sufficient cash flow to meet its obligations on a
timely basis, and (4) achieve satisfactory levels of future earnings. If
the Managing General Partner is unsuccessful in its efforts, it may be
unable to meet its obligations making it necessary to undertake such other
actions as may be appropriate to preserve asset values.
Information Systems for the Year 2000
The Managing General Partner provides all data processing needs of the
Partnership. The Managing General Partner has identified and assessed its
exposure to the potential Year 2000 software and imbedded chip processing
and date sensitivity issue. Through the Managing General Partners data
processing subsidiary, Midland Southwest Software, Inc., the Managing
General Partner proactively initiated an internal plan to identify
applicable hardware and software, assess impact and effect, estimate costs,
construct and implement corrective actions, and prepare contingency plans.
Identification & Assessment
The Managing General Partner currently believes it identified the internal
and external software and hardware that had the potential for date
sensitivity problems. Four critical systems and/or functions were
identified and addressed: (1) the proprietary software of the Partnership
(OGAS) that is used for oil & gas property management and financial
accounting functions, (2) the DEC VAX/VMS hardware and operating system,
(3) various third-party application software including lease economic
analysis, fixed asset management, geological applications, and
payroll/human resource programs, and (4) External Agents.
The proprietary software of the Partnership has met compliance
requirements. Since this is an internally generated software package, the
Managing General Partner incurred approximately $25,000 in man-hours.
Modifications were made by internal staff and did not represent additional
costs to the Partnership. The Managing General Partner has not made
contingency plans at this time since the conversion is ahead of schedule
and being handled by Managing General Partner controlled internal
programmers. Given the complexity of the systems that were modified, it is
anticipated that some problems may arise, but having met the early
completion date, the Managing General Partner feels that adequate time
remains available to overcome unforeseen delays.
<PAGE>
DEC has released a fully compliant version of its operating system that is
used by the Partnership on the DEC VAX system. It was installed, the
Managing General Partner believes that this solved any potential problems
on the system.
The Managing General Partner has identified various third-party software
that may have date sensitivity problems and is continuing to work with the
vendors to secure solutions as well as prepare contingency plans. After
review and evaluation of the vendor plans and status, the Managing General
Partner believes that the problems will be resolved prior to the year 2000
or the alternate contingency plan will sufficiently and adequately
remediate the problem so that there is no material disruption to business
functions.
The External Agents of the Partnership include suppliers, customers,
owners, vendors, banks, product purchasers including pipelines, and other
oil and gas property operators. The Managing General Partner is in the
process of identifying and communicating with each critical External Agent
about its plan and progress thereof in addressing the Year 2000 issue.
This process is on schedule and the Managing General Partner, at this time,
believes that there should be no material interference or disruption
associated with any of the critical External Agent's functions necessary to
the Partnership's business. The Managing General Partner estimates
completion of this audit by year end 1999 and believes that alternate plans
can be devised to circumvent any material problems arising from critical
External Agent noncompliance.
Cost
To date, the Managing General Partner has incurred only minimal internal
man-hour costs for identification, planning, and maintenance. The Managing
General Partner believes that the necessary additional costs will also be
minimal and most will fall under normal and general maintenance procedures
and updates. An accurate cost cannot be determined at this time, but it is
expected that the total cost to remediate all systems to be less than
$50,000.
Risks/Contingency
The failure to correct critical systems of the Partnership, or the failure
of a material business partner or External Agent to resolve critical Year
2000 issues could have a serious adverse impact on the ability of the
Partnership to continue operations and meet obligations. Based on the
Managing General Partner's evaluation and assessment to date, it is
believed that any interruption in operation will be minor and short-lived
and pose no material monetary loss, safety, or environmental risk to the
Partnership. However, due to the external nature of the potential
problems, it is impossible to accurately identify the risks, quantify
potential impacts or establish a final contingency plan. The Managing
General Partner believes that its assessment and contingency planning will
be complete no later than year-end 1999.
<PAGE>
Worst Case Scenario
The Securities and Exchange Commission requires public companies to
forecast the most reasonably likely worst case Year 2000 scenario, assuming
that the Managing General Partner's Year 2000 plan is not effective.
Analysis of the most reasonably likely worst case Year 2000 scenarios the
Partnership may face leads to contemplation of the following possibilities
which, though considered highly unlikely, must be included in any
consideration of worst cases: widespread failure of electrical, gas, and
similar supplies by utilities serving the Partnership; widespread
disruption of the services of communications common carriers; similar
disruption to means and modes of transportation for the Partnership and its
employees, contractors, suppliers, and customers; significant disruption to
the Partnership's ability to gain access to, and continue working in,
office buildings and other facilities; and the failure, of third-parties
systems, the effects of which would have a cumulative material adverse
impact on the Partnership's critical systems. The Partnership could
experience an inability by customers, traders, and others to pay, on a
timely basis or at all, obligations owed to the Partnership. Under these
circumstances, the adverse effect on the Partnership, and the diminution of
Partnership revenues, could be material, although not quantifiable at this
time.
<PAGE>
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)Exhibits:
27 Financial Data Schedule
(b) No reports on Form 8-K were filed during the quarter for
which this report is filed.
<PAGE>
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, Vice President
and Chief Financial Officer
Date: November 15, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Balance Sheet at September 30, 1999 (Unaudited) and the Statement of
Operations for the Nine Months Ended September 30, 1999 (Unaudited) and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 16,129
<SECURITIES> 0
<RECEIVABLES> 33,629
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 49,758
<PP&E> 1,314,434
<DEPRECIATION> 1,083,240
<TOTAL-ASSETS> 280,952
<CURRENT-LIABILITIES> 60
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 280,892
<TOTAL-LIABILITY-AND-EQUITY> 280,952
<SALES> 172,948
<TOTAL-REVENUES> 173,096
<CGS> 80,174
<TOTAL-COSTS> 80,174
<OTHER-EXPENSES> 25,458
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 67,464
<INCOME-TAX> 0
<INCOME-CONTINUING> 67,464
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 67,464
<EPS-BASIC> 41.74
<EPS-DILUTED> 41.74
</TABLE>
