Page 6 of 15
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, 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 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 15.
<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 notes 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 month
period ended March 31, 1999 are not necessarily indicative of the results
that may be expected for the full year.
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Balance Sheets
March 31, December 31,
1999 1998
--------- ------------
(unaudited)
Assets
Current assets:
Cash and equivalents $ 16,207 10,719
Receivable from Managing General Partner 11,293 241
--------- ---------
Total current assets 27,500 10,960
--------- ---------
Oil and gas properties - using the
full-cost method of accounting 1,098,374 1,097,568
Less accumulated depreciation,
depletion and amortization 920,000 913,000
--------- ---------
Net oil and gas properties 178,374 184,568
--------- ---------
$ 205,874 195,528
========= =========
Liabilities and Partners' Equity
Current liability - Distribution payable $ 2,630 2,630
--------- ---------
Partners' equity:
Managing General Partner 23,619 21,711
Investor partners 179,625 171,187
--------- ---------
Total partners' equity 203,244 192,898
--------- ---------
$ 205,874 195,528
========= =========
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
1999 1998
---- ----
Revenues
Oil and gas $ 39,171 50,233
Interest 12 21
------- -------
39,183 50,254
------- -------
Expenses
Production 17,336 18,510
General and administrative 4,501 9,570
Depreciation, depletion and amortization 7,000 12,000
------- -------
28,837 40,080
------- -------
Net income $ 10,346 10,174
======= =======
Net income allocated to:
Managing General Partner $ 1,908 2,439
======= =======
Investor partners $ 8,438 7,735
======= =======
Per investor partner unit $ 7.37 6.76
======= =======
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
1999 1998
---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 33,708 55,112
Cash paid to suppliers (27,426) (26,592)
Interest received 12 21
------- -------
Net cash provided by operating activities 6,294 28,541
------- -------
Cash flows used in investing activities:
Additions to oil and gas properties (806) (19,064)
------- -------
Cash flows used in financing activities:
Distributions to partners - (8,336)
------- -------
Net increase in cash and cash equivalents 5,488 1,141
Beginning of period 10,719 3,477
------- -------
End of period $ 16,207 4,618
======= =======
(continued)
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Cash Flows, continued
(unaudited)
Three Months Ended
March 31,
1999 1998
---- ----
Reconciliation of net income to
net cash provided by operating activities:
Net income $ 10,346 10,174
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation, depletion and amortization 7,000 12,000
Decrease (increase) in receivables (5,463) 4,879
Increase (decrease) in payables (5,589) 1,488
------ -------
Net cash provided by operating activities $ 6,294 28,541
====== =======
<PAGE>
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 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 March 31, 1999, and for the
three months ended March 31, 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 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 a normal decline, for
the life of these properties.
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. As of March 31, 1999, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves. A continuation
of the oil price environment experienced during 1998 will 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 March 31, 1999 and 1998
The following table provides certain information regarding performance
factors for the quarters ended March 31, 1999 and 1998:
Three Months
Ended Percentage
March 31, Increase
1999 1998 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 11.08 13.85 (20%)
Average price per mcf of gas $ 1.35 1.93 (30%)
Oil production in barrels 3,000 2,900 3%
Gas production in mcf 4,400 5,200 (15%)
Gross oil and gas revenue $ 39,171 50,233 (22%)
Net oil and gas revenue $ 21,835 31,723 (31%)
Partnership distributions $ - 8,500 (100%)
Investor partner distributions $ - 7,565 (100%)
Per unit distribution to investor
partners $ - 6.61 (100%)
Number of investor partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $39,171 from $50,233
for the quarters ended March 31, 1999 and 1998, respectively, a decrease of
22%. The principal factors affecting the comparison of the quarters ended
March 31, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the quarter ended March 31, 1999 as compared to the
quarter ended March 31, 1998 by 20%, or $2.77 per barrel, resulting in
a decrease of approximately $8,000 in revenues. Oil sales represented
85% of total oil and gas sales during the quarter ended March 31, 1999
as compared to 80% during the quarter ended March 31, 1998.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 30%, or $.58 per mcf, resulting in
a decrease of approximately $3,000 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $11,000. 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 100 barrels or 3% during the
quarter ended March 31, 1999 as compared to the quarter ended March 31,
1998, resulting in an increase of approximately $1,100 in revenues.
Gas production decreased approximately 800 mcf or 15% during the same
period, resulting in a decrease of approximately $1,100 in revenues.
No change in revenues due to the change in production for the quarter
ended March 31,1999.
Costs and Expenses
Total costs and expenses decreased to $28,837 from $40,080 for the quarters
ended March 31, 1999 and 1998, respectively, a decrease of 28%. The
decrease is the result of lower lease operating costs, depletion expense
and general and administrative expense.
1. Lease operating costs and production taxes were 6% lower, or
approximately $1,200 less during the quarter ended March 31, 1999 as
compared to the quarter ended March 31, 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
53% or approximately $5,100 during the quarter ended March 31, 1999 as
compared to the quarter ended March 31, 1998. The decrease of general
and administrative costs for the quarter 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 $7,000 for the quarter ended March 31,
1999 from $12,000 for the same period in 1998. This represents a
decrease of 42%. 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 decrease of depletion expense between the comparative
periods were the decrease in oil and gas revenue and the decrease in
the price of oil used to determine the Partnership's reserves.
<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 $6,300 in
the quarter ended March 31, 1999 as compared to approximately $28,500 in
the quarter ended March 31, 1998. The primary source of the 1999 cash flow
from operating activities was profitable operations.
Cash flows used in investing activities in the quarter ended March 31, 1999
were approximately $800. Cash flows used in investing activities in the
quarter ended March 31, 1998 were approximately $19,000. The principle use
of the 1999 cash flow from investing activities was the additions to oil
and gas properties.
There were no cash flows used in financing activities in the quarter ended
March 31, 1999 as compared to approximately $8,300 in the quarter ended
March 31, 1998. The only use in financing activities would be
distributions to partners.
There were no distributions during the quarter ended March 31, 1999. Total
distributions during the quarter ended March 31, 1998 were $8,500 of which
$7,565 was distributed to the investor partners and $935 to the Managing
General Partner. The per unit distribution to investor partners during the
quarter ended March 31, 1998 was $6.61.
The primary source for the 1998 distributions of $8,300 was oil and gas
operations of approximately $28,500.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,127,740 have been made to the partners. As of March 31, 1999,
$1,005,600 or $878.64 per investor partner unit has been distributed to the
investor partners, representing a 88% return of the capital contributed.
As of March 31, 1999, the Partnership had approximately $24,900 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.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
over $21.0 million of interest payments due in 1999 on its debt
obligations. Due to severely depressed commodity prices, 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.
<PAGE>
Information Systems for the Year 2000
The Managing General Partner provides all data processing needs of the
Partnership. The Managing General Partner is continuing in its effort to
identify and assess 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 a 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 has identified the
internal and external software and hardware that may have date sensitivity
problems. Four critical systems and/or functions were identified: (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 is currently in process of
meeting compliance requirements with an estimated completion date of mid-
year 1999. Since this is an internally generated software package, the
Managing General Partner has estimated the cost to be approximately $25,000
by estimating the necessary man-hours. These modifications are being made
by internal staff and do 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 being modified, it is anticipated that some problems may arise,
but with an expected early completion date, the Managing General Partner
feels that adequate time is available to overcome unforeseen delays.
DEC has released a fully compliant version of its operating system that is
used by the Partnership on the DEC VAX system. It will be installed in
August 1999, the Managing General Partner believes that this will solve any
potential problems on the system.
The Managing General Partner has identified various third-party software
that may have date sensitivity problems and is working 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 mid-year 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.
<PAGE>
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, until all assessment is complete, 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 mid-year
1999.
Worst Case Scenario
The Securities and Exchange Commission requires that public companies must
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) Reports on Form 8-K:
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 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 14, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Balance Sheet at March 31, 1999 (Unaudited) and the Statement of Operations
for the Three Months Ended March 31, 1999 (Unaudited) and is qualified in
its entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<CASH> 16,207
<SECURITIES> 0
<RECEIVABLES> 11,293
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 27,500
<PP&E> 1,098,374
<DEPRECIATION> 920,000
<TOTAL-ASSETS> 205,874
<CURRENT-LIABILITIES> 2,630
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 203,244
<TOTAL-LIABILITY-AND-EQUITY> 205,874
<SALES> 39,171
<TOTAL-REVENUES> 39,183
<CGS> 17,336
<TOTAL-COSTS> 17,336
<OTHER-EXPENSES> 11,501
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 10,346
<INCOME-TAX> 0
<INCOME-CONTINUING> 10,346
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 10,346
<EPS-PRIMARY> 7.37
<EPS-DILUTED> 7.37
</TABLE>
