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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [Fee Required]
For the fiscal year ended December 31, 1998
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required]
For the transition period from to
Commission File Number 33-38511
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 (I.R.S. Employer
of incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300, Midland, Texas 79701
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (915) 686-9927
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
limited and general partner interests
Indicate by check mark whether registrant (1) has filed reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [x]
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is ___. There is no
exhibit index.
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 6
3. Legal Proceedings 8
4. Submission of Matters to a Vote of Security Holders 8
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 9
6. Selected Financial Data 10
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 11
8. Financial Statements and Supplementary Data 20
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 38
Part III
10. Directors and Executive Officers of the Registrant 39
11. Executive Compensation 41
12. Security Ownership of Certain Beneficial Owners and
Management 41
13. Certain Relationships and Related Transactions 43
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 44
Signatures 45
Part I
Item 1. Business
General
Southwest Developmental Drilling Fund 91-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on January 7,
1991. The offering of 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, reached minimum capital
requirements on April 22, 1992 and concluded April 30, 1992. The
Partnership has no subsidiaries.
The Partnership has expended its capital and acquired leasehold interests
and completed drilling operations. The Partnership has produced and
marketed the crude oil and natural gas produced from such properties.
The principal executive offices of the Partnership are located at 407 N.
Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner
of the Partnership, Southwest Royalties, Inc. (the "Managing General
Partner") and its staff of 98 individuals, together with certain
independent consultants used on an "as needed" basis, perform various
services on behalf of the Partnership, including the selection of oil and
gas properties and the marketing of production from such properties. The
Partnership has no employees.
Principal Products, Marketing and Distribution
The Partnership has acquired leasehold interests and drilled oil and gas
properties located in Texas and New Mexico. All activities of the
Partnership are confined to the continental United States. All oil and gas
produced from these properties is sold to unrelated third parties in the
oil and gas business.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. The prices received by
the Partnership for its oil and gas production depend upon numerous factors
beyond the Partnership's control, including competition, economic,
political and regulatory developments and competitive energy sources, and
make it particularly difficult to estimate future prices of oil and natural
gas.
During 1998 oil prices fell to their lowest daily levels since 1986 and to
their lowest annual average since 1976. In two years, oil prices have been
sliced by more than half. The factors that started the decline in oil
prices in 1997 are the same ones that have kept them down in 1998. It was
believed that there would be continued heavy consumption coming from the
Asian region, but the collapse of their markets late in 1997 carried over
to this year bringing demand down with it. Asian consumption had all but
disappeared in 1998, creating an oversupply of crude oil on the market.
That drop in demand has lasted longer than anyone had anticipated, but
hopes of a recovery abound. Another reason for the continued drop in
prices has been OPEC's unwillingness to completely comply with production
cuts established in March and again in June. Although they have been near
90% compliance at times, they have also been below 70% on a monthly basis.
Even a four-day bombing in December of Iraqi military sites could create
only a one-day rally in oil prices. Crude oil closed December 31, 1998 at
$12.05 per barrel on the NYMEX and posted prices closed at $9.50 per
barrel.
In a year of fairly optimistic expectations for gas prices, the average
price of natural gas wound up declining in 1998 to its lowest level since
1995. Although the nationwide average did remain above $2.00 per MMBTU,
1998's prices were approximately 17% lower than those seen in 1997. The
combination of mild weather throughout the year and a gas storage surplus
both contributed to the low prices. Analysts' predictions for 1999 prices
vary, ranging from a low of $1.87 per MMBTU to a high of $2.40 per MMBTU.
Reduced production throughout the U.S. industry, along with large gas
storage withdrawals during the first weeks of January 1999, are both key
factors in our belief that the 1999 average gas price will remain around
$1.80 per MMBTU level.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
1998 83% 17%
1997 85% 15%
1996 82% 18%
As the table indicates, the majority of the Partnership's revenue is from
its oil production; therefore, Partnership revenues will be highly
dependent upon the future prices and demands for oil.
Seasonality of Business
Although the demand for natural gas is highly seasonal, with higher demand
in the colder winter months and in very hot summer months, the Partnership
has been able to sell all of its natural gas, either through contracts in
place or on the spot market at the then prevailing spot market price. As a
result, the volumes sold by the Partnership have not fluctuated materially
with the change of season.
Customer Dependence
No material portion of the Partnership's business is dependent on a single
purchaser, or a very few purchasers, where the loss of one would have a
material adverse impact on the Partnership. Three purchasers accounted for
93% of the Partnership's total oil and gas production during 1998: Navajo
Refining Company, Inc. for 45%, Scurlock Permian Corporation 38% and
Phillips 66 Natural Gas Company for 10%. Two purchasers accounted for 83%
of the Partnership's total oil and gas production during 1997: Navajo
Refining Company, Inc. for 49%, and Scurlock Permian Corporation for 34%.
Three purchasers accounted for 94% of the Partnership's total oil and gas
production during 1996: Navajo Refining Company, Inc. for 48%, Scurlock
Permian Corporation for 34% and Aquila Southwest Pipeline Corporation for
12%. All purchasers of the Partnership's oil and gas production are
unrelated third parties. In the event this purchaser were to discontinue
purchasing the Partnership's production, the Managing General Partner
believes that a substitute purchaser or purchasers could be located without
undue delay. No other purchaser accounted for an amount equal to or
greater than 10% of the Partnership's total oil and gas production.
Competition
Because the Partnership has utilized all of its funds available for the
acquisition of interests in producing oil and gas properties or drilling
operations, it is not subject to competition from other oil and gas
property purchasers. See Item 2, Properties.
Factors that may adversely affect the Partnership include delays in
completing arrangements for the sale of production, availability of a
market for production, rising operating costs of producing oil and gas and
complying with applicable water and air pollution control statutes,
increasing costs and difficulties of transportation, and marketing of
competitive fuels. Moreover, domestic oil and gas must compete with
imported oil and gas and with coal, atomic energy, hydroelectric power and
other forms of energy.
Oil and Gas Production - The production and sale of oil and gas is subject
to federal and state governmental regulation in several respects, such as
existing price controls on natural gas and possible price controls on crude
oil, regulation of oil and gas production by state and local governmental
agencies, pollution and environmental controls and various other direct and
indirect regulation. Many jurisdictions have periodically imposed
limitations on oil and gas production by restricting the rate of flow for
oil and gas wells below their actual capacity to produce and by imposing
acreage limitations for the drilling of wells. The federal government has
the power to permit increases in the amount of oil imported from other
countries and to impose pollution control measures.
Various aspects of the Partnership's oil and gas activities are regulated
by administrative agencies under statutory provisions of the states where
such activities are conducted and by certain agencies of the federal
government for operations on Federal leases. Moreover, certain prices at
which the Partnership may sell its natural gas production are controlled by
the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act
of 1989 and the regulations promulgated by the Federal Energy Regulatory
Commission.
Environmental - The Partnership's oil and gas activities are subject to
extensive federal, state and local laws and regulations governing the
generation, storage, handling, emission, transportation and discharge of
materials into the environment. Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties. This regulatory burden on the oil and gas industry increases
its cost of doing business and consequently affects its profitability. The
Managing General Partner is unable to predict what, if any, effect
compliance will have on the Partnership.
Industry Regulations and Guidelines - Certain industry regulations and
guidelines apply to the registration, qualification and operation of oil
and gas programs in the form of limited partnerships. The Partnership is
subject to these guidelines which regulate and restrict transactions
between the Managing General Partner and the Partnership. The Partnership
complies with these guidelines and the Managing General Partner does not
anticipate that continued compliance will have a material adverse effect on
Partnership operations.
Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a staff of geologists, engineers, accountants, landsmen and clerical staff
who engage in Partnership activities and operations and perform additional
services for the Partnership as needed. In addition to the Managing
General Partner's staff, the Partnership engages independent consultants
such as petroleum engineers and geologists as needed. As of December 31,
1998 there were 98 individuals directly employed by the Managing General
Partner in various capacities.
Item 2. Properties
In determining whether an interest in a particular property was to be
acquired, the Managing General Partner considered such criteria as
estimated oil and gas reserves, estimated drilling costs, estimated cash
flow from the sale of production, present and future prices of oil and gas,
the extent of undeveloped and unproved reserves, the potential for
secondary, tertiary and other enhanced recovery projects and the
availability of markets.
As of December 31, 1998, the Partnership possessed an interest in oil and
gas properties located in Eddy County of New Mexico and Rains, Van Zandt
and Ward County of Texas. These properties consist of various interests in
4 wells.
Due to the Partnership's objective of maintaining current operations
without engaging in the drilling of any developmental or exploratory wells,
or additional acquisitions of producing properties, there has not been any
significant changes in properties during 1998, 1997 and 1996.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and Location and Interest Wells Oil (bbls) Gas (mcf)
- ----------------- ------------ ----- ---------- ---------
Carson F #1 6/92 1 11,000 11,000
Ward County, 89%
Texas working
interest
Dagger Draw A #1 11/92 2 35,000 57,000
Eddy County, 45%
New Mexico working
interest
*Ryder Scott Company Petroleum Engineers prepared the reserve and present
value data for 96.4% of the Partnership's existing properties as of January
1, 1999. Another independent petroleum engineer prepared the remaining
3.6% of the Partnership's. The reserve estimates were made in accordance
with guidelines established by the Securities and Exchange Commission
pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil
and gas reserve reports be prepared under existing economic and operating
conditions with no provisions for price and cost escalation except by
contractual arrangements.
The New York Mercantile Exchange price at December 31, 1998 of $12.05 was
used as the beginning basis for the oil price. Oil price adjustments from
$12.05 per barrel were made in the individual evaluations to reflect oil
quality, gathering and transportation costs. The results are an average
price received at the lease of $11.10 per barrel in the preparation of the
reserve report as of January 1, 1999.
In the determination of the gas price, the New York Mercantile Exchange
price at December 31, 1998 of $1.95 was used as the beginning basis. Gas
price adjustments from $1.95 per Mcf were made in the individual
evaluations to reflect BTU content, gathering and transportation costs and
gas processing and shrinkage. The results are an average price received at
the lease of $1.41 per Mcf in the preparation of the reserve report as of
January 1, 1999.
As also discussed in Part II, Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations, oil and gas prices were
subject to frequent changes in 1998.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly with
respect to the quantity of oil or gas that any given property is capable of
producing. Estimates of oil and gas reserves are based on available
geological and engineering data, the extent and quality of which may vary
in each case and, in certain instances, may prove to be inaccurate.
Consequently, properties may be depleted more rapidly than the geological
and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than
previously estimated; thus an ultimately lower return for the Partnership.
Basic changes in past reserve estimates occur annually. As new data is
gathered during the subsequent year, the engineer must revise his earlier
estimates. A year of new information, which is pertinent to the estimation
of future recoverable volumes, is available during the subsequent year
evaluation. In applying industry standards and procedures, the new data
may cause the previous estimates to be revised. This revision may increase
or decrease the earlier estimated volumes. Pertinent information gathered
during the year may include actual production and decline rates, production
from offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs, among
others. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing and proved developed non-producing. All of the proved reserves
are included in the engineering reports which evaluate the Partnership's
present reserves.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth
quarter of 1998 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
Market Information
Investor partner interests, or units, in the Partnership were initially
offered and sold for a price of $1,000. Investor partner units are not
traded on any exchange and there is no public or organized trading market
for them. Further, a transferee may not become a substitute limited or
general partner without the consent of the Managing General Partner.
Each Additional General Partner interest, whom elected at the time of
subscription into the Partnership, has been converted into a limited
partner effective January 1, 1994.
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell. The
value of the unit is determined by adding the sum of (1) current assets
less liabilities and (2) the present value of the future net revenues
attributable to proved reserves and by discounting the future net revenues
at a rate not in excess of the prime rate charged by NationsBank, N.A. of
Midland, Texas plus one percent (1%), which value shall be further reduced
by a risk factor discount of no more than one-third (1/3) to be determined
by the Managing General Partner in its sole and absolute discretion. As of
December 31, 1998, 1997 and 1996, no limited partner units were purchased
by the Managing General Partner.
Number of Limited and General Partner Interest Holders
As of December 31, 1998, there were 99 holders of limited partner units and
no holders of general partner units in the Partnership.
Distributions
Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and
Agreement of Limited Partnership, "Net Cash Flow" is distributed to the
partners on a monthly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's drilling activities, less (i) General and
Administrative Costs, (ii) Operating Costs, and (iii) any reserves
necessary to meet current and anticipated needs of the Partnership,
including, but not limited to drilling cost overruns, as determined in the
sole discretion of the Managing General Partner."
During 1998, distributions were made totaling $40,500, with $36,045
distributed to the investor partners and $4,455 to the Managing General
Partner. For the year ended December 31, 1998, distributions of $31.49 per
investor partner unit were made, based upon 1,144.50 investor partner units
outstanding. The decline in distribution experienced in 1998 will be
expected to continue into 1999 based on the continued low oil price
economy. During 1997, twelve monthly distributions were made totaling
$290,000, with $258,100 distributed to the investor partners and $31,900 to
the Managing General Partner. For the year ended December 31, 1997,
distributions of $225.51 per investor partner unit were made, based upon
1,144.50 investor partner units outstanding. During 1996, twelve monthly
distributions were made totaling $253,000, with $225,170 distributed to the
investor partners and $27,830 to the Managing General Partner. For the
year ended December 31, 1996, distributions of $196.74 per investor partner
unit were made, based upon 1,144.5 investor partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
1998, 1997, 1996, 1995 and 1994 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
-----------------------------------------------------
Restated
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Revenues $ 172,847 307,526 480,994 276,584 383,345
Net income (3,178) 126,704 278,970 40,828 98,047
Partners' share of
net income:
Managing General
Partner 5,480 20,529 38,903 14,247 23,841
Investor partners (8,658) 106,175 240,067 26,581 74,206
Investor partners'
net income
per unit (7.57) 92.77 209.76 23.22 64.84
Investor partners'
cash distributions
per unit 31.49 225.51 196.74 86.32 138.42
Total assets $ 195,528 236,923 399,872 373,960 447,164
Item 7. 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 limited
and general partner interests began on 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 on 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 contribution was $9,800. Total capital
contributions were $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 limited partners and to the extent
necessary, acquire leases which contain drilling prospects. Net revenues
will not be reinvested in other revenue producing assets except to the
extent that performance of remedial work is needed to improve a well's
producing capabilities. The economic life of the Partnership thus depends
on the period over which the Partnership's oil and gas reserves are
economically recoverable.
Based on current conditions, management anticipates performing no workovers
during 1999 to enhance production. With expected price improvement,
workovers may be performed in the year 2000. The partnership may have an
increase in the year 2000, otherwise, the Partnership will most likely
experience it's historical decline of approximately 17% per year.
Results of Operations
A. General Comparison of the Years Ended December 31, 1998 and 1997
The following table provides certain information regarding performance
factors for the years ended December 31, 1998 and 1997:
Year Ended
December 31, Percentage
Increase
1998 1997 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 12.74 20.10 (37%)
Average price per mcf of gas $ 1.60 2.14 (25%)
Oil production in barrels 11,300 12,900 (12%)
Gas production in mcf 17,800 21,200 (16%)
Gross oil and gas revenue $ 172,545 304,617 (43%)
Net oil and gas revenue $ 72,410 201,996 (64%)
Partnership distributions $ 40,500 290,000 (86%)
Limited partner distributions $ 36,045 258,100 (86%)
Per unit distribution to limited partners $ 31.49 225.51 (86%)
Number of limited partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $172,545 from $304,617
for the years ended December 31, 1998 and 1997, respectively, a decrease of
43%. The principal factors affecting the comparison of the years ended
December 31, 1998 and 1997 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 1998 as compared to the
year ended December 31, 1997 by 37%, or $7.36 per barrel, resulting in
a decrease of approximately $94,900 in revenues. Oil sales represented
83% of total oil and gas sales during the year ended December 31, 1998
as compared to 85% during the year ended December 31, 1997.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 25%, or $.54 per mcf, resulting in
a decrease of approximately $11,400 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $106,300. 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.
2. Oil production decreased approximately 1,600 barrels or 12% during the
year ended December 31, 1998 as compared to the year ended December 31,
1997, resulting in a decrease of approximately $20,400 in revenues.
Gas production decreased approximately 3,400 mcf or 16% during the same
period, resulting in a decrease of approximately $5,400 in revenues.
The total decrease in revenues due to the change in production is
approximately $25,800. The decrease in production is due to downtime
on one gas well and sharp natural decline.
Costs and Expenses
Total costs and expenses decreased to $176,025 from $180,822 for the years
ended December 31, 1998 and 1997, respectively, a decrease of 3%. The
decrease is the result of lower lease operating costs and depletion
expense, partially offset by an increase in general and administrative
costs.
1. Lease operating costs and production taxes were 2% lower, or
approximately $2,500 less during the year ended December 31, 1998 as
compared to the year ended December 31, 1997.
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
25% or approximately $4,600 during the year ended December 31, 1998 as
compared to the year ended December 31, 1997. The increase in general
and administrative costs are the result of higher accounting fees due
to the necessity of contracting out preparation of tax depletion and K-
1 schedules.
3. Depletion expense decreased to $53,000 for the year ended December 31,
1998 from $58,000 for the same period in 1998. This represents a
decrease of 9%. 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.
A contributing factor to the decline in depletion expense between the
comparative periods was the impact of revisions of previous estimates
on reserves. Revisions of previous estimates can be attributed to the
changes in production performance, oil and gas price and production
costs. The impact of the revision would have decreased depletion
expense approximately $10,000 as of December 31, 1997.
Results of Operations
B. General Comparison of the Years Ended December 31, 1997 and 1996,
Restated
The following table provides certain information regarding performance
factors for the years ended December 31, 1997 and 1996:
Year Ended
December 31, Percentage
Restated Increase
1997 1996 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 20.10 20.88 (4%)
Average price per mcf of gas $ 2.14 2.40 (11%)
Oil production in barrels 12,900 18,700 (31%)
Gas production in mcf 21,200 36,800 (43%)
Gross oil and gas revenue $ 304,617 478,785 (37%)
Net oil and gas revenue $ 201,996 370,034 (46%)
Partnership distributions $ 290,000 253,000 15%
Limited partner distributions $ 258,100 225,170 15%
Per unit distribution to limited partners $ 225.51 196.74 15%
Number of limited partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $304,617 from $478,785
for the years ended December 31, 1997 and 1996, respectively, a decrease of
37%. The principal factors affecting the comparison of the years ended
December 31, 1997 and 1996 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 1997 as compared to the
year ended December 31, 1996 by 4%, or $.78 per barrel, resulting in a
decrease of approximately $14,580 in revenues. Oil sales represented
85% of total oil and gas sales during the year ended December 31, 1997
as compared to 82% during the year ended December 31, 1996.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 11%, or $.26 per mcf, resulting in
a decrease of approximately $9,560 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $24,140. The market price
for oil and gas has been extremely volatile over the past decade and
management expects a certain amount of volatility to continue in the
foreseeable future.
2. Oil production decreased approximately 5,800 barrels or 31% during the
year ended December 31, 1997 as compared to the year ended December 31,
1996, resulting in a decrease of approximately $116,580 in revenues.
Gas production decreased approximately 15,600 mcf or 43% during the
same period, resulting in a decrease of approximately $33,400 in
revenues.
The total decrease in revenues due to the change in production is
approximately $149,980. The decrease in production is due to normal
decline.
Costs and Expenses
Total costs and expenses decreased to $180,822 from $202,024 for the years
ended December 31, 1997 and 1996, respectively, a decrease of 11%. The
decrease is the result of lower lease operating costs, general and
administrative expense and depletion expense.
2. Lease operating costs and production taxes were 6% lower, or
approximately $6,000 less during the year ended December 31, 1997 as
compared to the year ended December 31, 1996.
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 2%
or approximately $300 during the year ended December 31, 1997 as
compared to the year ended December 31, 1996.
3. Depletion expense decreased to $58,000 for the year ended December 31,
1997 from $67,000 for the same period in 1996. This represents a
decrease of 14%. 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.
A contributing factor to the decline in depletion expense between the
comparative periods was the impact of revisions of previous estimates
on reserves. Revisions of previous estimates can be attributed to the
changes in production performance, oil and gas price and production
costs. The impact of the revision would have increased depletion
expense approximately $8,000 as of December 31, 1996.
C. Revenue and Distribution Comparison
Partnership net income (loss) for the years ended December 31, 1998, 1997
and 1996 was $(3,178), $126,704, and $278,970, respectively. Excluding the
effects of depreciation, depletion and amortization, net income for the
years ended December 31, 1998, 1997 and 1996 was $49,822 $186,627 and
$353,662, respectively. Correspondingly, Partnership distributions for the
years ended December 31, 1998, 1997 and 1996 were $40,500, $290,000 and
$253,000, respectively. These differences are indicative of the changes in
oil and gas price, production and property during 1998, 1997 and 1996.
The sources for the 1998 distributions of $40,500 were oil and gas
operations of approximately $67,300 and the change in oil and gas
properties of approximately $(21,800), resulting in excess cash for
contingencies or subsequent distributions. The sources for the 1997
distributions of $290,000 were oil and gas operations of approximately
$229,500 and the change in oil and gas properties of approximately
$(9,400), with the balance from available cash on hand at the beginning of
the period. The sources for the 1996 distributions of $253,000 were oil
and gas operations of approximately $320,800, offset additions to oil and
gas properties of approximately $(46,000), resulting in excess cash for
contingencies or subsequent distributions.
Total distributions during the year ended December 31, 1998 were $40,500 of
which $36,045 was distributed to the investor partners and $4,455 to the
Managing General Partner. The per unit distribution to investor partners
during the same period was $31.49. Total distributions during the year
ended December 31, 1997 were $290,000 of which $258,100 was distributed to
the investor partners and $31,900 to the Managing General Partner. The per
unit distribution to investor partners during the same period was $225.51.
Total distributions during the year ended December 31, 1996 were $253,000
of which $225,170 was distributed to the investor partners and $27,830 to
the Managing General Partner. The per unit distribution to investor
partners during the same period was $196.74.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,127,740 have been made to the partners. As of December 31, 1998,
$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.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
oil and gas properties. The Partnership anticipates the primary source of
cash to continue being from the oil and gas operations.
Cash flows provided by operating activities were approximately $67,300 in
1998 compared to $229,500 in 1997 and approximately $320,800 in 1996. The
primary source of the 1998 cash flow from operating activities was
profitable operations.
Cash flows used by investing activities were approximately $ 21,800 in 1998
compared to $9,400 in 1997 and approximately $46,300 in 1996. The principal
use of the 1998 cash flow from investing activities was additions to oil
and gas properties.
Cash flows used in financing activities were approximately $38,200 in 1998
compared to $289,600 in 1997 and approximately $253,100 in 1996. The only
use in the 1998 financing activities was the distributions to partners.
As of December 31, 1998, the Partnership had approximately $8,300 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenue 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.
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.
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.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Independent Auditors Reports 21
Balance Sheets 23
Statements of Operations 24
Statement of Changes in Partners' Equity 25
Statements of Cash Flows 26
Notes to Financial Statements 28
INDEPENDENT AUDITORS REPORT
The Partners
Southwest Developmental Drilling
Fund 91-A, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Developmental
Drilling Fund 91-A, L.P. (the "Partnership") as of December 31, 1998 and
1997, and the related statements of operations, changes in partners' equity
and cash flows for the years then ended. These financial statements are
the responsibility of the Partnership's management. Our responsibility is
to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Developmental
Drilling Fund 91-A, L.P. as of December 31, 1998 and 1997 and the results
of its operations and its cash flows for the years then ended in conformity
with generally accepted accounting principles.
KPMG LLP
Midland, Texas
March 18, 1999
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners
Southwest Developmental Drilling
Fund 91-A, L.P.
(A Delaware Limited Partnership)
We have audited the accompanying statements of operations, changes in
partners' equity and cash flows of Southwest Developmental Drilling Fund 91-
A, L.P. for the year ended December 31, 1996. These financial statements
are the responsibility of the partnership's management. Our responsibility
is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the statements of operations,
changes in partners equity and cash flows are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the statements of operations,
changes in partners equity and cash flows. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the
statements of operations, changes in partners equity and cash flows. We
believe that our audit of the statements of operations, changes in partners
equity and cash flows provides a reasonable basis for our opinion.
In our opinion, the statements of operations, changes in partners equity
and cash flows referred to above present fairly, in all material respects,
the results of operations and cash flows of Southwest Developmental
Drilling Fund 91-A, L.P. for the year ended December 31, 1996, in
conformity with generally accepted accounting principles.
JOSEPH DECOSIMO AND COMPANY
A Tennessee Registered Limited Liability
Partnership
Chattanooga, Tennessee
March 14, 1997, except for note 7, as
to which the date is March 25, 1998
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 1998 and 1997
1998 1997
---- ----
Assets
Current assets:
Cash and cash equivalents $ 10,719 3,477
Receivable from Managing General Partner 241 17,702
- --------- ---------
Total current assets
10,960 21,179
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 1,097,568 1,075,744
Less accumulated depreciation,
depletion and amortization
913,000 860,000
- --------- ---------
Net oil and gas properties
184,568 215,744
- --------- ---------
$
195,528 236,923
========= =========
Liabilities and Partners' Equity
Current liabilities:
Distribution payable $ 2,630 347
- --------- ---------
Partners' equity:
Managing General Partner 21,711 20,686
Investor partners 171,187 215,890
- --------- ---------
Total partners' equity
192,898 236,576
- --------- ---------
$
195,528 236,923
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statements of Operations
For the years ended December 31, 1998, 1997 and 1996
Restated
1998 1997 1996
---- ---- ----
Revenues
Oil and gas sales $ 172,545 304,617 478,785
Interest income from operations 302 2,909 2,209
-------
- ------- -------
172,847
307,526 480,994
-------
- ------- -------
Expenses
Production 100,135 102,621 108,751
General and administrative 22,890 18,278 18,581
Depreciation, depletion and amortization 53,000 59,923 74,692
-------
- ------- -------
176,025
180,822 202,024
-------
- ------- -------
Net income (loss) $ (3,178) 126,704 278,970
=======
======= =======
Net income (loss) allocated to:
Managing General Partner $ 5,480 20,529 38,903
=======
======= =======
Investor partners $ (8,658) 106,175 240,067
=======
======= =======
Per investor partner unit $ (7.57) 92.77 209.76
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
For the years ended December 31, 1998, 1997 and 1996
Managing
General Investor
Partner Partners Total
------- -------- -----
Balance at December 31, 1995 $ 20,984 352,918 373,902
Net income 38,903 240,067 278,970
Distributions (27,830) (225,170)(253,000)
-------
- -------- --------
Balance at December 31, 1996, Restated 32,057 367,815 399,872
Net income 20,529 106,175 126,704
Distributions (31,900) (258,100)(290,000)
-------
- -------- --------
Balance at December 31, 1997 20,686 215,890 236,576
Net income (loss) 5,480 (8,658) (3,178)
Distributions (4,455) (36,045) (40,500)
-------
- -------- --------
Balance at December 31, 1998 $ 21,711 171,187 192,898
=======
======== ========
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
For the years ended December 31, 1998, 1997 and 1996
Restated
1998 1997 1996
---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 188,548 343,716 447,823
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(121,567) (117,118)(129,254)
Interest received 302 2,909 2,209
--------
- -------- --------
Net cash provided by operating activities 67,283 229,507
320,778
--------
- -------- --------
Cash flows from investing activities:
Additions to oil and gas properties (21,824) (9,368) (46,330)
--------
- -------- --------
Cash flows used in financing activities:
Distributions to partners (38,217) (289,653)(253,058)
--------
- -------- --------
Net increase (decrease) in cash and cash
equivalents 7,242 (69,514) 21,390
Beginning of period 3,477 72,991 51,601
--------
- -------- --------
End of period $ 10,719 3,477 72,991
========
======== ========
(continued)
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows, continued
Years ended December 31, 1998, 1997 and 1996
Restated
1998 1997 1996
---- ---- ----
Reconciliation of net income to net cash
provided by operating activities:
Net income $ (3,178) 126,704 278,970
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 53,000 59,923
74,692
(Increase) decrease in receivables 16,003 39,099 (30,962)
Increase (Decrease) in payables 1,458 3,781 (1,922)
-------
- ------- -------
Net cash provided by operating activities $ 67,283 229,507 320,778
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
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.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. Gain or loss on
the sale of oil and gas properties is not recognized unless
significant oil and gas reserves are involved.
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.
Under the units of revenue method, the Partnership computes the
provision by multiplying the total unamortized cost of oil and gas
properties by an overall rate determined by dividing (a) oil and gas
revenues during the period by (b) the total future gross oil and gas
revenues as estimated by the Partnership's independent petroleum
consultants. It is reasonably possible that those estimates of
anticipated future gross revenues, the remaining estimated economic
life of the product, or both could be changed significantly in the
near term due to the potential fluctuation of oil and gas prices or
production. The depletion estimate would also be affected by this
change.
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 December 31, 1998, 1997 and 1996
the net capitalized costs did not exceed the estimated present value
of oil and gas reserves.
Estimates and Uncertainties
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Syndication Costs
Syndication costs are accounted for as a reduction of partnership
equity.
Environmental Costs
The Partnership is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and
may require the Partnership to remove or mitigate the environmental
effects of the disposal or release of petroleum or chemical substances
at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Costs which
improve a property as compared with the condition of the property when
originally constructed or acquired and costs which prevent future
environmental contamination are capitalized. Expenditures that relate
to an existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for expenditures
of a non-capital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably
estimated.
Gas Balancing
The Partnership utilizes the sales method of accounting for gas-
balancing arrangements. Under this method the Partnership recognizes
sales revenue on all gas sold. As of December 31, 1998, 1997 and
1996, there were no significant amounts of imbalance in terms of units
and value.
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," the
Partnership's tax basis in its net oil and gas properties at December
31, 1998 and 1997 is $144,886 and $155,958, respectively, less than
that shown on the accompanying Balance Sheets in accordance with
generally accepted accounting principles.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Partnership considers
all highly liquid debt instruments purchased with a maturity of three
months or less to be cash equivalents. The Partnership maintains its
cash at one financial institution.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Number of Investor Partner Units
As of December 31, 1998, 1997 and 1996, there were 1,144.5 investor
partner units outstanding held by 99 partners.
Concentrations of Credit Risk
The Partnership is subject to credit risk through trade receivables.
Although a substantial portion of its debtors' ability to pay is
dependent upon the oil and gas industry, credit risk is minimized due
to a large customer base. All partnership revenues are received by
the Managing General Partner and subsequently remitted to the
partnership and all expenses are paid by the Managing General Partner
and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair
value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
3. 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.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
shall be further reduced by a risk factor discount of no more than one-
third (1/3) to be determined by the Managing General Partner in its
sole and absolute discretion.
The Partnership is subject to various federal, state and local
environmental laws and regulations which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 1998, the Partnership has not been fined, cited or
notified of any environmental violations and management is not aware
of any unasserted violations which would have a material adverse
effect upon capital expenditures, earnings or the competitive position
in the oil and gas industry. However, the Managing General Partner
does recognize by the very nature of its business, material costs
could be incurred in the near term to bring the Partnership into total
compliance. The amount of such future expenditures is not reliably
determinable due to several factors, including the unknown magnitude
of possible contaminations, the unknown timing and extent of the
corrective actions which may be required, the determination of the
Partnership's liability in proportion to other responsible parties and
the extent to which such expenditures are recoverable from insurance
or indemnifications from prior owners of Partnership's properties.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As is usual in the industry and as provided
for in the operating agreement for each respective oil and gas
property in which the Partnership has an interest, the operator is
paid an amount for administrative overhead attributable to operating
such properties, with such amounts to Southwest Royalties, Inc. as
operator approximating $13,400, $12,000 and $13,000 for the years
ended December 31, 1998, 1997 and 1996, respectively. In addition,
the Managing General Partner and certain officers and employees may
have an interest in some of the properties that the Partnership also
participates.
Certain subsidiaries or affiliates of the Managing General Partner
perform various oilfield services for properties in which the
Partnership owns an interest. Such services aggregated approximately
$3,200, none and $6,600 for the years ended December 31, 1998, 1997
and 1996, respectively, and the Managing General Partner believes that
these costs are comparable to similar charges paid by the Partnership
to unrelated third parties.
Southwest Royalties, Inc., the Managing General Partner, was paid
$10,793 during 1998 and $12,000 during 1997 and 1996 for indirect
general and administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $241 and $17,702 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 1998 and 1997, respectively.
In addition, a director and officer of the Managing General Partner is
a partner in a law firm, with such firm providing legal services to
the Partnership approximating none, $30 and $20 for the years ended
December 31, 1998, 1997 and 1996, respectively.
6. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchasers, where the loss of one
would have a material adverse impact on the Partnership. Three
purchasers accounted for 93% of the Partnership's total oil and gas
production during 1998: Navajo Refining Company, Inc. for 45%,
Scurlock Permian Corporation 38% and Phillips 66 Natural Gas Company
for 10%. Two purchasers accounted for 83% of the Partnership's total
oil and gas production during 1997: Navajo Refining Company, Inc. 49%,
and Scurlock Permian Corporation 34%. Three purchasers accounted for
94% of the Partnership's total oil and gas production during 1996:
Navajo Refining Company, Inc. 48%, Scurlock Permian Corporation 34%
and Aquila Southwest Pipeline Corporation 12%. All purchasers of the
Partnership's oil and gas production are unrelated third parties. In
the event this purchaser were to discontinue purchasing the
Partnership's production, the Managing General Partner believes that a
substitute purchaser or purchasers could be located without undue
delay. No other purchaser accounted for an amount equal to or greater
than 10% of the Partnership's total oil and gas production.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil (bbls) Gas (mcf)
---------- ---------
Proved developed and undeveloped
reserves -
January 1, 1996 44,000 98,000
Revisions of estimates in place 49,000 80,000
Production (19,000) (37,000)
------- -------
December 31, 1996 74,000 141,000
Revisions of estimates in place (6,000) (50,000)
Production (13,000) (21,000)
------- -------
December 31, 1997 55,000 70,000
Revisions of estimates in place 2,000 16,000
Production (11,000) (18,000)
------- -------
December 31, 1998 46,000 68,000
======= =======
Proved developed reserves -
December 31, 1996 66,000 129,000
======= =======
December 31, 1997 55,000 70,000
======= =======
December 31, 1998 46,000 68,000
======= =======
All of the Partnership's reserves are located within the continental
United States.
*Ryder Scott Company Petroleum Engineers prepared the reserve and
present value data for 96.4% of the Partnership's existing properties
as of January 1, 1999. Another independent petroleum engineer
prepared the remaining 3.6% of the Partnership's properties. The
reserve estimates were made in accordance with guidelines established
by the Securities and Exchange Commission pursuant to Rule 4-10(a) of
Regulation S-X. Such guidelines require oil and gas reserve reports
be prepared under existing economic and operating conditions with no
provisions for price and cost escalation except by contractual
arrangements.
The New York Mercantile Exchange price at December 31, 1998 of $12.50
was used as the beginning basis for the oil price. Oil price
adjustments from $12.50 per barrel were made in the individual
evaluations to reflect oil quality, gathering and transportation
costs. The results are an average price received at the lease of
$11.10 per barrel in the preparation of the reserve report as of
January 1, 1999.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
In the determination of the gas price, the New York Mercantile
Exchange price at December 31, 1998 of $1.95 was used as the beginning
basis. Gas price adjustments from $1.95 per Mcf were made in the
individual evaluations to reflect BTU content, gathering and
transportation costs and gas processing and shrinkage. The results
are an average price received at the lease of $1.41 per Mcf in the
preparation of the reserve report as of January 1, 1999.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing and proved developed non-producing. All of the proved
reserves are included in the engineering reports which evaluate the
Partnership's present reserves
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 1998, 1997 and 1996 is
presented below:
1998 1997 1996
---- ---- ----
Future cash inflows $ 602,000 1,127,000 2,464,000
Production and development costs 374,000 565,000 983,000
--------- --------- ---------
Future net cash flows 228,000 562,000 1,481,000
10% annual discount for estimated
timing of cash flows 47,000 112,000 357,000
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 275,000 450,000 1,124,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
1998, 1997 and 1996 are as follows:
1998 1997 1996
---- ---- ----
Sales of oil and gas produced,
net of production costs $ (73,000) (202,000) (403,000)
Changes in prices and production costs (339,000) (472,000)
290,000
Changes of production rates
(timing) and others 169,000 (19,000) 47,000
Revisions of previous
quantities estimates 23,000 (93,000) 767,000
Accretion of discount 45,000 112,000 43,000
Discounted future net
cash flows -
Beginning of year 450,000 1,124,000 380,000
--------- -------- --------
End of year $ 275,000 450,000 1,124,000
========= ======== ========
Future net cash flows were computed using year-end prices and costs
that related to existing proved oil and gas reserves in which the
Partnership has mineral interests.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
Note 7 - Prior Period adjustment
The Managing General Partner, who is a related party, incorrectly billed
the Partnership for property costs as workover expense on one lease during
March 1996. This error resulted in the understatement of previously
reported property costs and the overstatement of depletion expense in the
prior year. The error was corrected in the September 1997 10-Q.
The following schedule shows the effect of the prior period adjustment,
before and after the restatement, to net income for the year ended December
31, 1996.
Before After
Prior Period Prior Period
Restatement Restatement
--------- --------
For the year ended December 31, 1996
Net income $ 241,841 278,970
Managing General Partner 33,829 38,903
Investor partners 208,012 240,067
Per investor partner unit 181.75 209.76
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
On June 9, 1997 Southwest Royalties, Inc. the Partnership's Managing
General Partner (Southwest Royalties, Inc.) dismissed Joseph Decosimo and
Company as the Partnership's independent accountants. The Managing General
Partner's Board of Directors approved the decision to change the
Partnership's independent accountants.
The report of Joseph Decosimo and Company on the financial statements for
the fiscal year ended December 31, 1996 contained no adverse opinion or
disclaimer of opinion and was not qualified or modified as to uncertainty,
audit scope or accounting principle.
In connection with its audit for the fiscal year ended December 31, 1996
and through June 9, 1997, there have been no disagreements with Joseph
Decosimo and Company on any matter of accounting principles or practices,
financial statements disclosure, or auditing scope or procedure, which
disagreements if not resolved to the satisfaction of Joseph Decosimo and
Company would have caused them to make reference thereto in their report on
the financial statements for such year.
The Registrant has requested that Joseph Decosimo and Company furnish it
with a letter addressed to the SEC stating whether or not is agrees with
the above statements. A copy of that letter is included as Exhibit 16 and
has been filed with the Securities and Exchange Commission.
Part III
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as
Managing General Partner. The names, ages, offices, positions and length
of service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below. Each director and executive officer serves for a
term of one year. The present directors of the Managing General Partner
have served in their capacity since the Company's formation in 1983.
Name Age Position
- -------------------- --- -----------------------------------
- -------
H. H. Wommack, III 43 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 42 Secretary and Director
Bill E. Coggin 44 Vice President and Chief
Financial Officer
Jon P. Tate 41 Vice President, Land and
Assistant Secretary
R. Douglas Keathley 43 Vice President, Operations
J. Steven Person 40 Vice President, Marketing
Paul L. Morris 57 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive
Officer, Treasurer, principal stockholder and a director of the Managing
General Partner, and has served as its President since the Company's
organization in August, 1983. Prior to the formation of the Company, Mr.
Wommack was a self-employed independent oil producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases,
and the drilling of exploratory and developmental oil and gas wells. Mr.
Wommack holds a J.D. degree from the University of Texas from which he
graduated in 1980, and a B.A. from the University of North Carolina in
1977.
H. Allen Corey, a founder of the Managing General Partner, has served as
the Managing General Partner's secretary and a director since its
inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew
pub restaurant chain based in the Southeast. Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga, Tennessee. He is currently of counsel to the law firm of
Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga,
Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University
Law School and B.A. degree from the University of North Carolina at Chapel
Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with
the Managing General Partner since 1985. Mr. Coggin was Controller for Rod
Ric Corporation of Midland, Texas, an oil and gas drilling company, during
the latter part of 1984. He was Controller for C.F. Lawrence & Associates,
Inc., an independent oil and gas operator also of Midland, Texas during the
early part of 1984. Mr. Coggin taught public school for four years prior
to his business experience. Mr. Coggin received a B.S. in Education and a
B.B.A. in Accounting from Angelo State University.
Jon P. Tate, Vice President, Land and Assistant Secretary, assumed his
responsibilities with the Managing General Partner in 1989. Prior to
joining the Managing General Partner, Mr. Tate was employed by C.F.
Lawrence & Associates, Inc., an independent oil and gas company, as Land
Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin
Landman's Association and received his B.B.S. degree from Hardin-Simmons
University.
R. Douglas Keathley, Vice President, Operations, assumed his
responsibilities with the Managing General Partner as a Production Engineer
in October, 1992. Prior to joining the Managing General Partner, Mr.
Keathley was employed for four (4) years by ARCO Oil & Gas Company as
senior drilling engineer working in all phases of well production (1988-
1992), eight (8) years by Reading & Bates Petroleum Company as senior
petroleum engineer responsible for drilling (1980-1988) and two (2) years
by Tenneco Oil Company as drilling engineer responsible for all phases of
drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum
Engineering in 1977 from the University of Oklahoma.
J. Steven Person, Vice President, Marketing, assumed his responsibilities
with the Managing General Partner as National Marketing Director in 1989.
Prior to joining the Managing General Partner, Mr. Person served as Vice
President of Marketing for CRI, Inc., and was associated with Capital
Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor
University in 1982 and an M.D.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings,
Inc. since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States. Prior to
his position with Wagner & Brown, Mr. Morris served as President of Banner
Energy and in various managerial positions with Columbia Gas System, Inc.
Key Employees
Accounting and Administrative Officer - Debbie A. Brock, age 46, assumed
her position with the Managing General Partner in 1991. Prior to joining
the Managing General Partner, Ms. Brock was employed with Western Container
Corporation as Accounting Manager (1982-1990), Synthetic Industries
(Texas), Inc. as Accounting Manager (1976-1982) and held various accounting
positions in the manufacturing industry (1971-1975). Ms. Brock received a
B.B.A. from the University of Houston.
Controller - Robert A. Langford, age 49, assumed his responsibilities with
the Managing General Partner in 1992. Mr. Langford received his B.B.A.
degree in Accounting in 1975 from the University of Central Arkansas.
Prior to joining the Managing General Partner, Mr. Langford was employed
with Forest Oil Corporation as Corporate Coordinator, Regional Coordinator,
Accounting Manager. He held various other positions from 1982-1992 and
1976-1980 and was Assistant Controller of National Oil Company from 1980-
1982.
Financial Reporting Manager - Bryan Dixon, C.P.A., age 32, assumed his
responsibilities with the Managing General Partner in 1992. Mr. Dixon
received his B.B.A. degree in Accounting in 1988 from Texas Tech University
in Lubbock, Texas. Prior to joining the Managing General Partner, Mr.
Dixon was employed as a Senior Auditor with Johnson, Miller & Company from
1991-1992 and Audit Supervisor for Texas Tech University and the Texas Tech
University Health Sciences Center from 1988-1991.
Production Superintendent - Steve C. Garner, age 57, assumed his
responsibilities with the Managing General Partner as Production
Superintendent in July, 1989. Prior to joining the Managing General
Partner, Mr. Garner was employed 16 years by Shell Oil Company working in
all phases of oil field production as operations foreman, one and one-half
years with Petroleum Corporation of Delaware as Production Superintendent,
six years as an independent engineering consultant, and one year with
Citation Oil & Gas Corp. as a workover, completion and production foreman.
Mr. Garner has worked extensively in the Permian Basin oil field for the
last 25 years.
Tax Manager - Carolyn Cookson, age 42, assumed her position with the
Managing General Partner in April, 1989. Prior to joining the Managing
General Partner, Ms. Cookson was employed as Director of Taxes at C.F.
Lawrence & Associates, Inc. from 1983 to 1989, and worked in public
accounting at McCleskey, Cook & Green, P.C. from 1981 to 1983 and Deanna
Brady, C.P.A. from 1980 to 1981. She is a member of the Permian Basin
Chapter of the Petroleum Accountants' Society, and serves on its Board of
Directors and is liaison to the Tax Committee. Ms. Cookson received a
B.B.A. in accounting from New Mexico State University.
Investor Relations Manager - Sandra K. Flournoy, age 52, came to Southwest
Royalties, Inc. in 1988 from Parker & Parsley Petroleum, where she was
Assistant Manager of Investor Services and Broker/Dealer Relations for two
years. Prior to that, Ms. Flournoy was Administrative Assistant to the
Superintendent at Greenwood ISD for four years.
In certain instances, the Managing General Partner will engage professional
petroleum consultants and other independent contractors, including
engineers and geologists in connection with property acquisitions,
geological and geophysical analysis, and reservoir engineering. The
Managing General Partner believes that, in addition to its own "in-house"
staff, the utilization of such consultants and independent contractors in
specific instances and on an "as-needed" basis allows for greater
flexibility and greater opportunity to perform its oil and gas activities
more economically and effectively.
Item 11. Executive Compensation
The Partnership does not have any directors or executive officers. The
executive officers of the Managing General Partner do not receive any cash
compensation, bonuses, deferred compensation or compensation pursuant to
any type of plan, from the Partnership. The Managing General Partner
received $10,793 during 1998 and $12,000 during 1997 and 1996 as an annual
administrative fee for reimbursement of indirect general and administrative
costs.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no limited partners who own of record, or are known by the
Managing General Partner to beneficially own, more than five percent of the
Partnership's limited partnership interests.
The Managing General Partner owns an 11 percent interest as a Managing
General Partner.
No officer or director of the Managing General Partner owns Units in the
Partnership. There are no arrangements known to the Managing General
Partner which may at a subsequent date result in a change of control of the
Partnership.
Item 13. Certain Relationships and Related Transactions
In 1998, the Managing General Partner received $10,793 as an administrative
fee. This amount is part of the general and administrative expenses
incurred by the Partnership.
In some instances the Managing General Partner and certain officers and
employees may be working interest owners in an oil and gas property in
which the Partnership also has a working interest. Certain properties in
which the Partnership has an interest are operated by the Managing General
Partner, who was paid approximately $13,400 for administrative overhead
attributable to operating such properties during 1998.
The law firm of Baker, Donelson, Bearman & Caldwell, of which H. Allen
Corey, an officer and director of the Managing General Partner, is a
partner, is counsel to the Partnership. Baker, Donelson, Bearman &
Caldwell provided services totaling approximately. There were no legal
services for the year ended December 31, 1998, which constitutes an
immaterial portion of that firm's business.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Reports of Independent Accountants
Balance Sheets
Statement of Operations
Statement of Changes in Partners' Equity
Statement of Cash Flows
Notes to Financial Statements
(2) Schedules required by Article 12 of Regulation S-
X are either omitted because they are not applicable or
because the required information is shown in the
financial statements or the notes thereto.
(3) Exhibits:
4 (a) Certificate of Limited
Partnership of Southwest Developmental Drilling
Fund 91-A, L.P., dated January 9, 1991.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1991.)
(b) Agreement of Limited
Partnership of Southwest Developmental Drilling
Fund 91-A, L.P. dated January 9, 1991.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1991.)
(c) Second Amended and Restated
Certificate of Limited Partnership of Southwest
Developmental Drilling Fund 91-A. L.P., dated as
of February 1, 1993. (Incorporated by reference
from Partnership's Form 10-K for the fiscal year
ended December 31, 1993.)
(d) Second Amended and Restated
Certificate of Limited Partnership of Southwest
Developmental Drilling Fund 91-A. L.P., dated as
of January 12, 1994. (Incorporated by reference
from Partnership's Form 10-K for the fiscal year
ended December 31, 1993.)
27 Financial Data Schedule
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 1998.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Partnership has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Developmental Drilling Fund 91-
A, L.P.,
a Delaware limited partnership
By: Southwest Royalties, Inc.,
Managing
General Partner
By: /s/ H. H. Wommack, III
-----------------------------
H. H. Wommack, III, President
Date: March 31, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III
-----------------------------------
H. H. Wommack, III, Chairman of the
Board, President, Chief Executive
Officer, Treasurer and Director
Date: March 31, 1999
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 31, 1999