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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 March 31, 2003
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission File Number 33-38511
SOUTHWEST DEVELOPMENTAL DRILLING PROGRAM 1991-92
Southwest Developmental Drilling Fund 91-A, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2387814
(State or other jurisdiction 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 19.
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 notes thereto for
the year ended December 31, 2002, which are found in the Registrant's Form
10-K Report for 2002 filed with the Securities and Exchange Commission.
The December 31, 2002 balance sheet included herein has been taken from the
Registrant's 2002 Form 10-K Report. Operating results for the three month
period ended March 31, 2003 are not necessarily indicative of the results
that may be expected for the full year.
Southwest Developmental Drilling Fund 91-A, L.P.
Balance Sheets
March December
31, 31,
2003 2002
---- ----
(unaudit
ed)
Assets
- ----------
Current assets:
Cash and cash equivalents $ 11,317 11,779
Receivable from Managing 10,139 4,069
General Partner
-------- --------
---- ----
Total current assets 21,456 15,848
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 1,123,48 1,107,84
1 9
Less accumulated
depreciation,
depletion and 1,002,16 993,000
amortization 6
-------- --------
---- ----
Net oil and gas 121,315 114,849
properties
-------- --------
---- ----
$ 142,771 130,697
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability:
Distribution payable $ 31 31
-------- --------
---- ----
Other long term liabilities 44,763 -
-------- --------
---- ----
Partners' equity:
Managing General Partner 21,078 23,666
Investor partners 76,899 107,000
-------- --------
---- ----
Total partners' equity 97,977 130,666
-------- --------
---- ----
$ 142,771 130,697
======= =======
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2003 2002
----- -----
Revenues
- -------------
Oil and gas $ 42,713 18,475
Interest - 2
-------- --------
- -
42,713 18,477
-------- --------
- -
Expenses
- ------------
Production 33,056 14,443
General and administrative 4,049 3,900
Depreciation, depletion and 5,000 2,000
amortization
Accretion 878 -
-------- --------
- -
42,983 20,343
-------- --------
- -
Net income (loss) before (270) (1,866)
cumulative effect
Cumulative effect of change (32,419) -
in accounting principle
-------- --------
- -
Net income (loss) $ (32,689) (1,866)
===== =====
Net income (loss) allocated
to:
Managing General Partner $ (2,588) 15
===== =====
Investor partners $ (30,101) (1,881)
===== =====
Per investor partner unit $ (26.30) (1.64)
===== =====
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2003 2002
----- -----
Cash flows from operating
activities:
Cash received from oil and gas $ 29,520 19,501
sales
Cash paid to suppliers (29,982) (20,480)
Interest received - 2
-------- --------
-- --
Net cash used in operating (462) (977)
activities
-------- --------
-- --
Net decrease in cash and cash (462) (977)
equivalents
Beginning of period 11,779 12,402
-------- --------
-- --
End of period $ 11,317 11,425
====== ======
Reconciliation of net income
(loss)
to net cash used in operating
activities:
Net income (loss) $ (32,689) (1,866)
Adjustments to reconcile net
income
(loss)to net cash used in
operating activities:
Depreciation, depletion and 5,000 2,000
amortization
Accretion 878 -
Cumulative effect of change in 32,419 -
accounting principle
(Increase) decrease in (13,193) 1,026
receivables
Increase (decrease) in payables 7,123 (2,137)
-------- --------
-- --
Net cash used in operating $ (462) (977)
activities
====== ======
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption $ 11,466 -
of SFAS No.143
====== ======
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 91-A, L.P. was organized under
the laws of the state of Delaware on January 7, 1991 for the purpose
of drilling developmental and exploratory wells and to produce and
market crude oil and natural gas produced from such properties for a
term of 50 years, unless terminated at an earlier date as provided for
in the Partnership Agreement. The Partnership sells its oil and gas
production to a variety of purchasers with the prices it receives
being dependent upon the oil and gas economy. Southwest Royalties,
Inc. serves as the Managing General Partner. Revenues, costs and
expenses are allocated as follows:
Managing
General Investor
Partner Partners
-------- --------
Interest income on - 100%
capital contributions
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and - 100%
offering costs (1)
Syndication costs - 100%
Amortization of - 100%
organization costs
Lease acquisition costs 1% 99%
Gain/loss on property 11% 89%
disposition*
Operating and 11% 89%
administrative
costs*(2)
Depreciation, depletion
and amortization
of oil and gas - 100%
properties
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.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
The interim financial information as of March 31, 2003, and for the
three months ended March 31, 2003, 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, 2002.
3. Cumulative effect of change in accounting principle
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required
for all companies with fiscal years beginning after June 15, 2002.
The new standard requires the Partnership to recognize a liability for
the present value of all legal obligations associated with the
retirement of tangible long-lived assets and to capitalize an equal
amount as a cost of the asset and depreciate the additional cost over
the estimated useful life of the asset. On January 1, 2003, the
Partnership recorded additional costs, net of accumulated
depreciation, of approximately $11,466, a long term liability of
approximately $43,885 and a charge of approximately $32,419 for the
cumulative effect on depreciation of the additional costs and
accretion expense on the liability related to expected abandonment
costs of its oil and natural gas producing properties. At March 31,
2003, the asset retirement obligation was $44,763, and the increase in
the balance from January 1, 2003 of $878 is due to accretion expense.
The pro forma amount of the asset retirement obligation was measured
using information, assumptions and interest rates as of the adoption
date of January 1, 2003. Assuming the Partnership had applied the
provisions of SFAS No. 143 for the three months ended March 31, 2002
pro forma net income (loss) and related income (loss) per limited
partner unit amounts would have been $(2,673) and $(2.34),
respectively.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 91-A, L.P. was organized as a
Delaware limited partnership on January 7, 1991. The offering of such
limited and general partner interests began September 17, 1991 as part of a
shelf offering registered under the name Southwest Developmental Drilling
Program 1991-92. Minimum capital requirements for the partnership were met
on April 22, 1992, with the offering of limited and general partner
interests concluding April 30, 1992, with total investor partner
contributions of $1,144,500. The Managing General Partner made a
contribution to the capital of the Partnership at the conclusion of its
offering period in an amount equal to 1% of its net capital contributions.
The Managing General Partner's contribution was $9,800. The total capital
contributions are $1,154,300.
The Partnership was formed to engage primarily in the business of drilling
developmental and exploratory wells, to produce and market crude oil and
natural gas produced from such properties, to distribute any net proceeds
from operations to the general and investor 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
during 2003 to enhance production. Additional workovers may be performed
in the year 2004. The partnership may have an increase in production
volumes for the year 2004, otherwise, the partnership will most likely
experience the historical production decline, which has approximated 14%
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.
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.
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 three
months ended March 31, 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 March 31, 2003, the net capitalized
costs did not exceed the estimated present value of oil and gas reserves.
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 on an annual basis prepared by outside consultants.
Quarterly reserve estimates are prepared by the Managing General Partner's
internal staff of engineers.
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.
Results of Operations
A. General Comparison of the Quarters Ended March 31, 2003 and 2002
The following table provides certain information regarding performance
factors for the quarters ended March 31, 2003 and 2002:
Three Months
Ended Percenta
ge
March 31, Increase
2003 2002 (Decreas
e)
----- ----- --------
-----
Average price per $ 33.01 67%
barrel of oil 19.76
Average price per mcf $ 5.39 191%
of gas 1.85
Oil production in 1,000 860 16%
barrels
Gas production in mcf 1,800 800 125%
Gross oil and gas $ 42,713 18,475 131%
revenue
Net oil and gas revenue $ 9,657 4,032 140%
Partnership $ - - -
distributions
Investor partner $ - - -
distributions
Per unit distribution -
to investor
partners $ - -
Number of investor 1,144.5 1,144.5
partner units
Revenues
The Partnership's oil and gas revenues increased to $42,713 from $18,475
for the quarters ended March 31, 2003 and 2002, respectively, an increase
of 131%. The principal factors affecting the comparison of the quarters
ended March 31, 2003 and 2002 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended March 31, 2003 as compared to the
quarter ended March 31, 2002 by 67%, or $13.25 per barrel, resulting in
an increase of approximately $13,300 in revenues. Oil sales
represented 77% of total oil and gas sales during the quarter ended
March 31, 2003 as compared to 92% during the quarter ended March 31,
2002.
The average price for an mcf of gas received by the Partnership
increased during the same period by 191%, or $3.54 per mcf, resulting
in an increase of approximately $6,400 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $19,700. 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 increased approximately 140 barrels or 16% during the
quarter ended March 31, 2003 as compared to the quarter ended March 31,
2002, resulting in an increase of approximately $2,800 in revenues.
Gas production increased approximately 1,000 mcf or 125% during the
same period, resulting in an increase of approximately $1,900 in
revenues.
The total increase in revenues due to the change in production is
approximately $4,700. The increase in oil production is primarily due
to two leases that fluctuate levels of production. The increase in gas
production is primarily due to a lease that experienced downtime during
2002, which was water production influenced and gas production has been
restored. In addition another lease fluctuates levels of production.
Costs and Expenses
Total costs and expenses increased to $42,983 from $20,343 for the quarters
ended March 31, 2003 and 2002, respectively, an increase of 111%. The
increase is a direct result of the accretion expense associated with our
long term liability related to expected abandonment costs of our oil and
natural gas properties, depletion expense, general and administrative
expense and lease operating costs.
1. Lease operating costs and production taxes were 129% higher, or
approximately $18,600 more during the quarter ended March 31, 2003 as
compared to the quarter ended March 31, 2002. The increase in lease
operating expense and production taxes is due primarily to one lease
performing repairs and maintenance, such as pulling expense, and the
increase in production taxes in relation to the increase in gross
revenues received in 2003.
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 $150 during the quarter ended March 31, 2003 as
compared to the quarter ended March 31, 2002.
3. Depletion expense increased to $5,000 for the quarter ended March 31,
2003 from $2,000 for the same period in 2002. This represents an
increase of 150%. 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. The effect of this change in estimate if the units of
production method were applied to 2002 would have increased 2002
depletion expense by $1,000 and decreased 2002 net income by $1,000.
The contributing factors to the increase in depletion expense is in
relation to the BOE depletion rate for the quarter ended March 31, 2003
was $4.14 applied to 1,300 BOE as compared to $2.99 applied to 993 BOE
for the same period.
Cumulative effect of change in accounting principle
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement Obligations
("SFAS No. 143"). Adoption of SFAS No. 143 is required for all companies
with fiscal years beginning after June 15, 2002. The new standard requires
the Partnership to recognize a liability for the present value of all legal
obligations associated with the retirement of tangible long-lived assets
and to capitalize an equal amount as a cost of the asset and depreciate the
additional cost over the estimated useful life of the asset. On January 1,
2003, the Partnership recorded additional costs, net of accumulated
depreciation, of approximately $11,466, a long term liability of
approximately $43,885 and a charge of approximately $32,419 for the
cumulative effect on depreciation of the additional costs and accretion
expense on the liability related to expected abandonment costs of its oil
and natural gas producing properties. At March 31, 2003, the asset
retirement obligation was $44,763, and the increase in the balance from
January 1, 2003 of $878 is due to accretion expense. The pro forma amount
of the asset retirement obligation was measured using information,
assumptions and interest rates as of the adoption date of January 1, 2003.
Assuming the Partnership had applied the provisions of SFAS No. 143 for the
three months ended March 31, 2002 pro forma net income (loss) and related
income (loss) per limited partner unit amounts would have been $(2,673) and
$(2.34), respectively.
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 used in operating activities were approximately $500 in the
quarter ended March 31, 2003 as compared to approximately $1,000 in the
quarter ended March 31, 2002.
Since inception of the Partnership, cumulative cash distributions of
$1,414,471 have been made to the partners. As of March 31, 2003,
$1,260,790 or $1,101.61 per investor partner unit has been distributed to
the investor partners, representing a 100% return of the capital and a 10%
return on capital contributed.
As of March 31, 2003, the Partnership had approximately $21,400 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 properties, the producing reserves continue to deplete
causing cash flow to steadily decline.
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. This statement has been adopted by the Partnership effective
January 1, 2003. The transition adjustment resulting from the adoption of
SFAS No. 143 has been reported as a cumulative effect of a change in
accounting principle.
In April 2004, the FASB issued Statement of Financial Accounting Standards
No. 149, Amendment of Statement No. 133 on Derivative Instruments and
Hedging Activities ("SFAS No. 149"). SFAS No. 149 amendments require that
contracts with comparable characteristics be accounted for similarly,
clarifies when a contract with an initial investment meets the
characteristic of a derivative and clarifies when a derivative requires
special reporting in the statement of cash flows. SFAS No. 149 is
effective for hedging relationships designated and for contracts entered
into or modified after June 30, 2003, except for provisions that relate to
SFAS No. 133 Statement Implementation Issues that have been effective for
fiscal quarters prior to June 15, 2003, should be applied in accordance
with their respective effective dates and certain provisions relating to
forward purchases or sales of when-issued securities or other securities
that do not yet exist, should be applied to existing contracts as well as
new contracts entered into after June 30, 2003. Assessment by the Managing
General Partner revealed this pronouncement to have no impact on the
partnership.
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) Exhibits:
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 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 91-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: May 15, 2003
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Developmental Drilling Fund 91-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: May 15, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-A, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Developmental Drilling Fund 91-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: May 15, 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 91-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 Quarterly Report of Southwest Developmental
Drilling Fund 91-A, Limited Partnership (the "Company") on Form 10-Q for
the period ending March 31, 2003 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, H.H. Wommack, III, Chief
Executive Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and results of
operation of the
Company.
Date: May 15, 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 91-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 Quarterly Report of Southwest Developmental
Drilling Fund 91-A, Limited Partnership (the "Company") on Form 10-Q for
the period ending March 31, 2003 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, Bill E. Coggin, Chief
Financial Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(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: May 15, 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 91-A, L.P.