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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
For the fiscal year ended December 31, 2002
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number 33-38511
Southwest Developmental Drilling 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 40. The exhibit
index is found on page 38.
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 5
3. Legal Proceedings 6
4. Submission of Matters to a Vote of Security Holders 6
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 7
6. Selected Financial Data 8
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 9
8. Financial Statements and Supplementary Data 16
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 29
Part III
10. Directors and Executive Officers of the Registrant 30
11. Executive Compensation 32
12. Security Ownership of Certain Beneficial Owners and
Management 32
13. Certain Relationships and Related Transactions 33
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 34
Signatures 35
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 82 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.
In 2002, fighting and threats of fighting in the Middle East and a strike
in a major oil exporting country dominated the direction of crude oil
prices. While OPEC agreed to keep production constant throughout the year,
conflicts between the U.S. and Iraq, as well as between Israel and the
Palestinians threatened supplies and caused oil prices to surge in 2002.
In addition, a strike by oil workers in Venezuela, the fourth largest
supplier to the U.S., took a significant amount of crude oil off the market
toward the end of the year. As a result, OPEC agreed in January 2003 to
increase output by 1.5 million barrels per day in an effort to make up for
the lost supply and stabilize prices.
In 2002, spot prices for natural gas fell by 27.5% from the unprecedented
heights reached in 2001, averaging just under $3.00/MMBtu for the year.
Most of the lowest prices were seen early on, with the first quarter
averaging of $2.24/MMBtu. But as the year progressed, prices climbed
higher, ending with a $3.99 average in December. As for 2003, industry
analysts are divided on their gas price predictions, with estimates ranging
anywhere from $4.00 to $6.00/MMBtu. Weather forecasts, storage inventory
levels, a tighter supply and demand balance, and the unstable situation
with Iraq are all factors that will have a significant impact on the
direction prices will take. Overall however, analysts are maintaining a
bullish perspective, expecting gas prices to remain at or above $4.00/MMBtu
in 2003.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
---- ----
2002 90% 10%
2001 82% 18%
2000 85% 15%
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. One purchaser accounted for
85% of the Partnership's total oil and gas production during 2002: Plains
Marketing LP for 85%. Two purchasers accounted for 94% of the
Partnership's total oil and gas production during 2001: Plains Marketing LP
for 76% and Duke Energy Field Services for 18%. Two purchasers accounted
for 91% of the Partnership's total oil and gas production during 2000:
Plains Marketing LP for 78% and Duke Energy Transport for 13%. 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, land men 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,
2002 there were 82 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, 2002, 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
5 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 have not been any
significant changes in properties during 2002, 2001 and 2000.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and and Interest Wells Oil Gas
Location (bbls) (mcf)
- ------------- ------------ ----- -------- --------
- ---- -- -
Carson F #1 6/92 1 19,000 18,000
Ward County, 89%
Texas working
interest
*Ryder Scott Company, L.P. prepared the reserve and present value data for
the Partnership's existing properties as of January 1, 2003. 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.
Oil price adjustments were made in the individual evaluations to reflect
oil quality, gathering and transportation costs. The results of the reserve
report as of January 1, 2003 are an average price of $29.68 per barrel.
Gas price adjustments were made in the individual evaluations to reflect
BTU content, gathering and transportation costs and gas processing and
shrinkage. The results of the reserve report as of January 1, 2003 are an
average price of $4.20 per Mcf.
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 2002.
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 2002 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, 2002, no limited partner units were purchased by the Managing
General Partner. Southwest, as Managing General Partner, evaluated several
liquidity alternatives for the partnerships in 2001 and 2002. During 2002,
Southwest specifically pursued the possible roll-up and merger of twenty-
one (21) partnerships with the general partner. Because of the
complexities and conflicts of interest in such a transaction, the Managing
General Partner did not make a formal repurchase offer in 2002 but has
responded to limited partners desiring to sell their units in the
partnerships on an "as requested" basis. Southwest anticipates that it
will maintain this policy in 2003 because the aforementioned transaction is
ongoing. In 2001, 17 limited partner units were tendered to and purchased
by the Managing General Partner at an average base price of $214.15 per
unit. As of December 31, 2000, no limited partner units were purchased by
the Managing General Partner.
Number of Limited and General Partner Interest Holders
As of December 31, 2002, there were 102 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 quarterly 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 2002, distributions were made totaling $18,462, with $16,431
distributed to the investor partners and $2,031 to the Managing General
Partner. For the year ended December 31, 2002, distributions of $14.36 per
investor partner unit were made, based upon 1,144.50 investor partner units
outstanding. During 2001, distributions were made totaling $62,234, with
$55,388 distributed to the investor partners and $6,846 to the Managing
General Partner. For the year ended December 31, 2001, distributions of
$48.39 per investor partner unit were made, based upon 1,144.50 investor
partner units outstanding. During 2000, quarterly distributions were made
totaling $121,035, with $107,721 distributed to the investor partners and
$13,314 to the Managing General Partner. For the year ended December 31,
2000, distributions of $94.12 per investor partner unit were made, based
upon 1,144.50 investor partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2002, 2001, 2000, 1999 and 1998 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
--------------------------------------------------
---
Restate
d
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Revenues $ 105,095 139,286 162,884 252,026 172,847
Net income 15,942 30,325 58,242 119,990 (3,178)
(loss)
Partners'
share of
net income
(loss):
Managing
General
Partner 3,184 5,536 7,617 17,159 5,480
Investor 12,758 24,789 50,625 102,831 (8,658)
partners
Investor
partners'
net income
(loss)
per unit 11.15
21.66 44.23 89.85 (7.57)
Investor
partners'
cash
distributions
per unit 14.36
48.39 94.12 66.10 31.49
Total assets $ 130,697 133,225 165,095 237,888 195,528
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 2003 to enhance production. Additional workovers may be performed
in the year 2004. The partnership may have an increase in production
volumes for the year 2004, otherwise, the partnership will most likely
experience the historical production decline, which have approximated 14%
per year.
Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost method
of accounting for its oil and gas properties. The full cost method
subjects companies to quarterly calculations of a "ceiling", or limitation
on the amount of properties that can be capitalized on the balance sheet.
If the Partnership's capitalized costs are in excess of the calculated
ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
Prior to October 1, 2002, the Partnership calculated depletion of oil and
gas properties under the units of revenue method. The Partnership changed
methods of estimating depletion effective October 1, 2002 to the units of
production method. The units of production method is more predominantly
used throughout the oil and gas industry and will allow the Partnership to
more closely align itself with its peers. This change in estimate had no
impact on depletion expense for the fourth quarter.
A. General Comparison of the Years Ended December 31, 2002 and 2001
The following table provides certain information regarding performance
factors for the years ended December 31, 2002 and 2001:
Year Ended Percenta
ge
December 31, Increase
2002 2001 (Decreas
e)
---- ---- --------
-
Average price per $ 24.96 (3%)
barrel of oil 25.84
Average price per mcf $ 2.83 (36%)
of gas 4.41
Oil production in 3,750 4,440 (16%)
barrels
Gas production in mcf 3,700 5,540 (33%)
Gross oil and gas $ 104,083 139,132 (25%)
revenue
Net oil and gas revenue $ 44,302 65,516 (32%)
Partnership $ 18,462 62,234 (70%)
distributions
Investor partner $ 16,431 55,388 (70%)
distributions
Per unit distribution $ 14.36 (70%)
to investor partners 48.39
Number of investor 1,144.5
partner units 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $104,083 from $139,132
for the years ended December 31, 2002 and 2001, respectively, a decrease of
25%. The principal factors affecting the comparison of the years ended
December 31, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 2002 as compared to the
year ended December 31, 2001 by 3%, or $.88 per barrel, resulting in a
decrease of approximately $3,300 in revenues. Oil sales represented 90%
of total oil and gas sales during the year ended December 31, 2002 as
compared to 82% during the year ended December 31, 2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 36%, or $1.58 per mcf, resulting in
a decrease of approximately $5,800 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $9,100. 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 690 barrels or 16% during the
year ended December 31, 2002 as compared to the year ended December 31,
2001, resulting in a decrease of approximately $17,800 in revenues.
Gas production decreased approximately 1,840 mcf or 33% during the same
period, resulting in a decrease of approximately $8,100 in revenues.
The total decrease in revenues due to the change in production is
approximately $25,900. The decrease in oil production is due to
fluctuation in production on one out of three leases. The decrease in
gas production is due primarily to downtime on one lease, which is
water production influenced and gas production cannot be restored, in
addition one lease experiences fluctuations in levels of production.
Costs and Expenses
Total costs and expenses decreased to $89,153 from $108,961 for the years
ended December 31, 2002 and 2001, respectively, a decrease of 18%. The
decrease is the result of lower depletion expense and lease operating
costs, partially offset an increase in general and administrative costs.
1. Lease operating costs and production taxes were 19% lower, or
approximately $13,800 less during the year ended December 31, 2002 as
compared to the year ended December 31, 2001. The decrease in lease
operating expense is due mainly to repairs and maintenance performed during
2001.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 7%
or approximately $1,000 during the year ended December 31, 2002 as
compared to the year ended December 31, 2001.
3. Depletion expense decreased to $13,000 for the year ended December 31,
2002 from $20,000 for the same period in 2001. This represents a
decrease of 35%. Prior to October 1, 2002, the Partnership calculated
depletion of oil and gas properties under the units of revenue method.
The Partnership changed methods of estimating depletion effective
October 1, 2002 to the units of production method. The units of
production method is more predominantly used throughout the oil and gas
industry and will allow the Partnership to more closely align itself
with its peers. This change in estimate had no impact on depletion
expense for the fourth quarter.
The major factor in the decrease in depletion expense between the
comparative periods was the increase in oil and gas prices of the 2003
reserves as compared to 2002, and the decrease in oil and gas revenues
received by the Partnership during 2002 as compared to 2001.
B. General Comparison of the Years Ended December 31, 2001 and 2000
The following table provides certain information regarding performance
factors for the years ended December 31, 2001 and 2000:
Year Ended Percenta
ge
December 31, Increase
2001 2000 (Decreas
e)
---- ---- --------
-
Average price per $ 25.84 (14%)
barrel of oil 29.88
Average price per mcf $ 4.41 15%
of gas 3.82
Oil production in 4,440 4,600 (3%)
barrels
Gas production in mcf 5,540 6,600 (16%)
Gross oil and gas $ 139,132 162,628 (14%)
revenue
Net oil and gas revenue $ 65,516 83,755 (22%)
Partnership $ 62,234 121,035 (49%)
distributions
Investor partner $ 55,388 107,721 (49%)
distributions
Per unit distribution $ 48.39 (49%)
to investor partners 94.12
Number of investor 1,144.5
partner units 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $139,132 from $162,628
for the years ended December 31, 2001 and 2000, respectively, a decrease of
14%. The principal factors affecting the comparison of the years ended
December 31, 2001 and 2000 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 2001 as compared to the
year ended December 31, 2000 by 14%, or $4.04 per barrel, resulting in
a decrease of approximately $17,900 in revenues. Oil sales represented
82% of total oil and gas sales during the year ended December 31, 2001
as compared to 85% during the year ended December 31, 2000.
The average price for an mcf of gas received by the Partnership
increased during the same period by 15%, or $.59 per mcf, resulting in
an increase of approximately $3,300 in revenues.
The net total decrease in revenues due to the change in prices received
from oil and gas production is approximately $14,600. 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 160 barrels or 3% during the
year ended December 31, 2001 as compared to the year ended December 31,
2000, resulting in a decrease of approximately $4,800 in revenues.
Gas production decreased approximately 1,060 mcf or 16% during the same
period, resulting in a decrease of approximately $4,000 in revenues.
The total decrease in revenues due to the change in production is
approximately $8,800. Gas production is down due to workovers being
performed on one lease.
Costs and Expenses
Total costs and expenses increased to $108,961 from $104,642 for the years
ended December 31, 2001 and 2000, respectively, an increase of 4%. The
increase is the result of higher depletion expense and general and
administrative costs, partially offset a decrease in lease operating costs.
1. Lease operating costs and production taxes were 7% lower, or
approximately $5,300 less during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 4%
or approximately $600 during the year ended December 31, 2001 as
compared to the year ended December 31, 2000.
3. Depletion expense increased to $20,000 for the year ended December 31,
2001 from $11,000 for the same period in 2000. This represents an
increase of 82%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants.
The major factor in the increase in depletion expense between the
comparative periods was the decrease in oil and gas prices of the 2002
reserves as compared to 2001, and the decrease in oil and gas revenues
received by the Partnership during 2001 as compared to 2000. 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 $10,000
as of December 31, 2000.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2002, 2001 and 2000
was $15,942, $30,325 and $58,242, respectively. Excluding the effects of
depreciation, depletion and amortization, net income for the years ended
December 31, 2002, 2001 and 2000 was $28,942, $50,325 and $69,242,
respectively. Correspondingly, Partnership distributions for the years
ended December 31, 2002, 2001 and 2000 were $18,462, $62,234 and $121,035,
respectively.
The sources for the 2002 distributions of $18,462 were oil and gas
operations of approximately $26,900 and the change in oil and gas
properties of approximately $(9,100), with the balance from available cash
on hand at the beginning of the period. The sources for the 2001
distributions of $62,234 were oil and gas operations of approximately
$60,400 and the change in oil and gas properties of approximately $(200),
with the balance from available cash on hand at the beginning of the
period. The sources for the 2000 distributions of $121,035 were oil and
gas operations of approximately $78,700 and the change in oil and gas
properties of approximately $(200), with the balance from available cash on
hand at the beginning of the period.
Total distributions during the year ended December 31, 2002 were $18,462 of
which $16,431 was distributed to the investor partners and $2,031 to the
Managing General Partner. The per unit distribution to investor partners
during the same period was $14.36. Total distributions during the year
ended December 31, 2001 were $62,234 of which $55,388 was distributed to
the investor partners and $6,846 to the Managing General Partner. The per
unit distribution to investor partners during the same period was $48.39.
Total distributions during the year ended December 31, 2000 were $121,035
of which $107,721 was distributed to the investor partners and $13,314 to
the Managing General Partner. The per unit distribution to investor
partners during the same period was $94.12.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,414,471 have been made to the partners. As of December 31, 2002,
$1,260,790 or $1,101.61 per investor partner unit, has been distributed to
the investor partners, representing a 100% return of capital and a 10%
return on 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 $26,900 in
2002 compared to $60,400 in 2001 and approximately $78,700 in 2000. The
primary source of the 2002 cash flow from operating activities was
profitable operations.
Cash flows used in investing activities were approximately $9,100 in 2002
compared to $200 in 2001 and approximately $200 in 2000. The principal use
of the 2002 cash flow from investing activities was additions to oil and
gas properties.
Cash flows used in financing activities were approximately $18,500 in 2002
compared to $62,200 in 2001 and approximately $120,400 in 2000. The only
use in the 2002 financing activities was the distributions to partners.
As of December 31, 2002, the Partnership had approximately $15,800 in
working capital. The Managing General Partner knows of no unusual
contractual commitments. Although the partnership held many long-lived
properties at inception, because of the restrictions on property
development imposed by the partnership agreement, the Managing General
Partner anticipates that at some point in the near future, the partnership
will need to be liquidated. Maintenance of properties and administrative
expenses are increasing relative to production. As the properties continue
to deplete, maintenance of properties and administrative costs as a
percentage of production will continue to increase.
As the partnerships properties have matured, the net cash flows from
operations for the partnership have generally declined, except in periods
of substantially increased commodity pricing. Since the partnership cannot
develop their non-producing properties, the producing reserves continue to
deplete causing cash flow to steadily decline.
On October 17, 2002, Southwest Royalties, Inc. the Managing General Partner
filed an S-4 "Registration of Securities, Business Combinations" with the
Securities and Exchange Commission. The S-4 relates to a proposed plan of
merger of twenty-one limited partnerships.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
approximately $124.0 million of principal due between December 31, 2002 and
December 31, 2004. The Managing General Partner is constantly monitoring
its cash position and its ability to meet its financial obligations as they
become due, and in this effort, is continually exploring various strategies
for addressing its current and future liquidity needs. The Managing
General Partner regularly pursues and evaluates recapitalization strategies
and acquisition opportunities (including opportunities to engage in
mergers, consolidations or other business combinations) and at any given
time may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to fund
debt service, developmental projects and day to day operations, but it is
not sufficient to build a cash balance which would allow the Managing
General Partner to meet its debt principal maturities scheduled for 2004.
Therefore the Managing General Partner must renegotiate the terms of its
various obligations or seek new lenders or equity investors in order to
meet its financial obligations, specifically those maturing in 2004. The
Managing General Partner may be required to dispose of certain assets in
order to meet its obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the debt holders will
agree to a course of action consistent with the Managing General Partner's
requirements in restructurings the obligations. Furthermore, there can be
no assurance that the sales of assets can be successfully accomplished on
terms acceptable to the Managing General Partner.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged. The Managing General Partner is currently assessing the impact
on the partnerships financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Independent Auditors Report 17
Balance Sheets 18
Statements of Operations 19
Statement of Changes in Partners' Equity 20
Statements of Cash Flows 21
Notes to Financial Statements 22
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, 2002 and
2001, and the related statements of operations, changes in partners' equity
and cash flows for each of the years in the three year period ended
December 31, 2002. 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 auditing standards generally
accepted in the United States of America. 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, 2002 and 2001 and the results
of its operations and its cash flows for each of the years in the three
year period ended December 31, 2002 in conformity with accounting
principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas
March 14, 2003
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2002 and 2001
2002 2001
---- ----
Assets
- ----------
Current assets:
Cash and cash equivalents $ 11,779 12,402
Receivable from Managing 4,069 2,047
General Partner
-------- --------
---- ----
Total current assets 15,848 14,449
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 1,107,84 1,098,77
9 6
Less accumulated
depreciation,
depletion and 993,000 980,000
amortization
-------- --------
---- ----
Net oil and gas 114,849 118,776
properties
-------- --------
---- ----
$ 130,697 133,225
======= ========
=
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability:
Distribution payable $ 31 39
-------- --------
---- ----
Partners' equity:
Managing General Partner 23,666 22,513
Investor partners 107,000 110,673
-------- --------
---- ----
Total partners' equity 130,666 133,186
-------- --------
---- ----
$ 130,697 133,225
======= ========
=
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, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
Revenues
- -------------
Oil and gas sales $ 104,083 139,132 162,628
Interest income from 9 154 256
operations
Miscellaneous 1,003 - -
-------- -------- --------
-- -- --
105,095 139,286 162,884
-------- -------- --------
-- -- --
Expenses
- -------------
Production 59,781 73,616 78,873
General and 16,372 15,345 14,769
administrative
Depreciation, depletion 13,000 20,000 11,000
and amortization
-------- -------- --------
-- -- --
89,153 108,961 104,642
-------- -------- --------
-- -- --
Net income $ 15,942 30,325 58,242
====== ====== ======
Net income allocated
to:
Managing General $ 3,184 5,536 7,617
Partner
====== ====== ======
Investor partners $ 12,758 24,789 50,625
====== ====== ======
Per investor partner $ 11.15
unit 21.66 44.23
====== ====== ======
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, 2002, 2001 and 2000
Managing
General Investor
Partner Partners Total
------- -------- -----
Balance at December 31, $ 29,520 198,368 227,888
1999
Net income 7,617 50,625 58,242
Distributions (13,314) (107,721 (121,035
) )
-------- -------- --------
-- --- ----
Balance at December 31, 23,823 141,272 165,095
2000
Net income 5,536 24,789 30,325
Distributions (6,846) (55,388) (62,234)
-------- -------- --------
-- --- ----
Balance at December 31, 22,513 110,673 133,186
2001
Net income 3,184 12,758 15,942
Distributions (2,031) (16,431) (18,462)
-------- -------- --------
-- --- ----
Balance at December 31, $ 23,666 107,000 130,666
2002
====== ====== =======
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, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
Cash flows from operating
activities:
Cash received from oil and $ 101,165 152,656 166,419
gas sales
Cash paid to Managing
General Partner
for administrative fees
and general
and administrative (75,257) (92,367) (87,964)
overhead
Interest received 9 154 256
Miscellaneous settlement 1,003 - -
-------- -------- --------
---- ---- ----
Net cash provided by 26,920 60,443 78,711
operating activities
-------- -------- --------
---- ---- ----
Cash flows used in investing
activities:
Additions to oil and gas (9,073) (184) (151)
properties
-------- -------- --------
---- ---- ----
Cash flows used in financing
activities:
Distributions to partners (18,470) (62,195) (120,418
)
-------- -------- --------
---- ---- ----
Net decrease in cash and
cash
equivalents (623) (1,936) (41,858)
Beginning of period 12,402 14,338 56,196
-------- -------- --------
---- ---- ----
End of period $ 11,779 12,402 14,338
======= ======= =======
Reconciliation of net income
to net
cash provided by operating
activities:
Net income $ 15,942 30,325 58,242
Adjustments to reconcile net
income to
net cash provided by
operating activities:
Depreciation, depletion and 13,000 20,000 11,000
amortization
(Increase) decrease in (2,918) 13,524 3,791
receivables
Increase (decrease) in 896 (3,406) 5,678
payables
-------- -------- --------
---- ---- ----
Net cash provided by $ 26,920 60,443 78,711
operating activities
======= ======= =======
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 - 100%
contributions
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and offering - 100%
costs (1)
Syndication costs - 100%
Amortization of organization - 100%
costs
Lease acquisition costs 1% 99%
Gain/loss on property 11% 89%
disposition*
Operating and administrative 11% 89%
costs*(2)
Depreciation, depletion and
amortization
of oil and gas properties - 100%
Intangible drilling and - 100%
development costs
All other costs* 11% 89%
*After the Investor Partners have received distributions totaling 150%
of their capital contributions, the allocation will change to 15%
Managing General Partner and 85% Investor Partners.
(1) All organization costs in excess of 4% of initial capital
contributions will be paid by the Managing General Partner and
will be treated as a capital contribution. The Partnership paid
the Managing General Partner an amount equal to 4% of initial
capital contributions for such organization costs.
(2) Administrative costs in any year, which exceed 2% of capital
contributions shall be paid by the Managing General Partner and
will be treated as a capital contribution.
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.
Prior to October 1, 2002, the Partnership calculated depletion of oil
and gas properties under the units of revenue method. The Partnership
changed methods of estimating depletion effective October 1, 2002 to
the units of production method. The units of production method is
more predominantly used throughout the oil and gas industry and will
allow the Partnership to more closely align itself with its peers.
This change in estimate had no impact on depletion expense for the
fourth quarter.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Oil and Gas Properties - continued
Should the net capitalized costs exceed the estimated present value of
oil and gas reserves, discounted at 10%, such excess costs would be
charged to current expense. In applying the units of revenue method
for the years ended December 31, 2001, 2000 and for the nine months
ended September 30, 2002, we have not excluded royalty and net profit
interest payments from gross revenues as all of our royalty and net
profit interests have been purchased and capitalized to the depletion
basis of our proved oil and gas properties. As of December 31, 2002,
2001 and 2000 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. The Partnerships depletion
calculation and full-cost ceiling test for oil and gas properties uses
oil and gas reserves estimates, which are inherently imprecise. Actual
results could differ from those estimates.
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.
Revenue Recognition
We recognize oil and gas sales when delivery to the purchaser has
occurred and title has transferred. This occurs when production has
been delivered to a pipeline or transport vehicle.
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, 2002, 2001 and
2000, there were no significant amounts of imbalance in terms of units
or 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, 2002 and 2001 is $110,013 and $113,822, respectively, less than
that shown on the accompanying Balance Sheets in accordance with
generally accepted accounting principles.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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.
Number of Investor Partner Units
As of December 31, 2002, 2001 and 2000, there were 1,144.5 investor
partner units outstanding held by 102, 102 and 103 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.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of
removal-type costs associated with asset retirements. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Managing General Partner is currently
assessing the impact on the partnerships financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure
with approximately $124.0 million of principal due between December
31, 2002 and December 31, 2004. The Managing General Partner is
constantly monitoring its cash position and its ability to meet its
financial obligations as they become due, and in this effort, is
continually exploring various strategies for addressing its current
and future liquidity needs. The Managing General Partner regularly
pursues and evaluates recapitalization strategies and acquisition
opportunities (including opportunities to engage in mergers,
consolidations or other business combinations) and at any given time
may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to
fund debt service, developmental projects and day to day operations,
but it is not sufficient to build a cash balance which would allow the
Managing General Partner to meet its debt principal maturities
scheduled for 2004. Therefore the Managing General Partner must
renegotiate the terms of its various obligations or seek new lenders
or equity investors in order to meet its financial obligations,
specifically those maturing in 2004. The Managing General Partner
would also 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 debt holders will
agree to a course of action consistent with the Managing General
Partner's requirements in restructurings the obligations.
Furthermore, there can be no assurance that the sales of assets can be
successfully accomplished on terms acceptable to the Managing General
Partner.
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.
Southwest, as Managing General Partner, evaluated several liquidity
alternatives for the partnerships in 2001 and 2002. During 2002,
Southwest specifically pursued the possible roll-up and merger of
twenty-one (21) partnerships with the general partner. Because of the
complexities and conflicts of interest in such a transaction, the
Managing General Partner did not make a formal repurchase offer in
2002 but has responded to limited partners desiring to sell their
units in the partnerships on an "as requested" basis. Southwest
anticipates that it will maintain this policy in 2003 because the
aforementioned transaction is ongoing.
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, 2002, 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 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 $12,100,
$11,800 and $11,400 for the years ended December 31, 2002, 2001 and
2000, respectively. The amounts for administrative overhead
attributable to operating the partnership properties have been
deducted from gross oil and gas revenues in the determination of net
profit interest. 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
$700, $1,100 and $4,300 for the years ended December 31, 2002, 2001
and 2000, respectively. The amounts for oilfield services performed
for the partnership by affiliates of the Managing General Partner have
been deducted from gross oil and gas revenues in the determination of
net profit interest.
Southwest Royalties, Inc., the Managing General Partner, was paid
$10,800 in 2002, 2001 and 2000 for indirect general and administrative
overhead expenses. The administrative fees are included in general
and administrative expense on the statement of operations.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $4,100 and $2,000 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2002 and 2001, 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. One
purchaser accounted for 85% of the Partnership's total oil and gas
production during 2002: Plains Marketing LP for 85%. Two purchasers
accounted for 94% of the Partnership's total oil and gas production
during 2001: Plains Marketing LP for 76% and Duke Energy Field
Services for 18%. Two purchasers accounted for 91% of the
Partnership's total oil and gas production during 2000: Plains
Marketing LP for 78% and Duke Energy Transport for 13%. 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 Gas
(bbls) (mcf)
-------- --------
-- -
Proved developed and
undeveloped reserves -
January 1, 2000 44,000 61,000
Revisions of estimates in 10,000 15,000
place
Production (5,000) (7,000)
-------- --------
-- --
December 31, 2000 49,000 69,000
Revisions of estimates in (20,000) (32,000)
place
Production (4,000) (6,000)
-------- --------
-- --
December 31, 2001 25,000 31,000
Revisions of estimates in 2,000 (1,000)
place
Production (4,000) (4,000)
-------- --------
-- --
December 31, 2002 23,000 26,000
====== ======
Proved developed reserves -
December 31, 2000 49,000 69,000
====== ======
December 31, 2001 25,000 31,000
====== ======
December 31, 2002 23,000 26,000
====== ======
All of the Partnership's reserves are located within the continental
United States.
*Ryder Scott Company, L.P. prepared the reserve and present value data
for the Partnership's existing properties as of January 1, 2003. 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.
Oil price adjustments were made in the individual evaluations to
reflect oil quality, gathering and transportation costs. The results
of the reserve report as of January 1, 2003 are an average price of
$29.68 per barrel.
Gas price adjustments were made in the individual evaluations to
reflect BTU content, gathering and transportation costs and gas
processing and shrinkage. The results of the reserve report as of
January 1, 2003 are an average price of $4.20 per Mcf.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
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
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2002, 2001 and 2000 is
presented below:
2002 2001 2000
---- ---- ----
Future cash inflows $ 805,000 553,000 1,966,00
0
Production and development 428,000 395,000 1,129,00
costs 0
-------- -------- --------
---- -- ----
Future net cash flows 377,000 158,000 837,000
10% annual discount for
estimated
timing of cash flows 103,000 37,000 275,000
-------- -------- --------
---- -- ----
Standardized measure of
discounted
future net cash flows $ 274,000 121,000 562,000
======= ====== =======
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil & Gas Reserves (unaudited) - continued
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2002, 2001 and 2000 are as follows:
2002 2001 2000
---- ---- ----
Sales of oil and gas
produced,
net of production costs $ (44,000) (66,000) (84,000)
Changes in prices and 174,000 (346,000 157,000
production costs )
Changes of production rates
(timing) and others (7,000) 16,000 (28,000)
Revisions of previous
quantities estimates 18,000 (101,000 116,000
)
Changes in estimated future
development costs - - 15,000
Accretion of discount 12,000 56,000 35,000
Discounted future net
cash flows -
Beginning of year 121,000 562,000 351,000
-------- -------- --------
-- -- --
End of year $ 274,000 121,000 562,000
====== ====== ======
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.
Quarter
--------------------------------------
--------
First Second Third Fourth
------ ------- ------ ------
2002:
Total revenues $ 18,477 31,744 25,395 29,479
Total expenses 20,343 21,068 19,650 28,092
Net income (loss) (1,866) 10,676 5,745 1,387
Net income (loss)
per limited
partners unit (1.64) .69
7.92 4.18
2001:
Total revenues $ 55,540 23,594 32,635 27,517
Total expenses 23,108 32,338 33,137 20,378
Net income (loss) 32,432 (8,744) (502) 7,139
Net income (loss)
per limited
partners unit 24.74
(7.18) (1.06) 5.16
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None
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.
Name Age Position
H. H. Wommack, III 47 Chairman of the Board,
President, Director
and Chief Executive Officer
James N. Chapman(1) 40 Director
William P. Nicoletti(2) 57 Director
Joseph J. Radecki, Jr. 44 Director
(2)
Richard D. Rinehart(1) 67 Director
John M. White(2) 46 Director
Herbert C. Williamson, 54 Director
III(1)
Bill E. Coggin 48 Executive Vice President and
Chief Financial Officer
J. Steven Person 44 Vice President, Marketing
(1) Member of the Compensation Committee
(2) Member of the Audit Committee
H. H. Wommack, III has served as Chairman of the Board, President, Chief
Executive Officer and a director since Southwest's founding in 1983. Since
1997 Mr. Wommack has served as President, Chief Executive Officer and
Chairman of SRH, Southwest's former parent and current holder of 10% of its
voting share capital. Since 1997 Mr. Wommack has served as chairman of the
board of directors of Midland Red Oak Realty, Inc. From 1997 until
December 2000, Mr. Wommack served as chairman of the board of directors of
Basic Energy Services, Inc. and since December 2000 has continued to serve
on Basic's board of directors. Prior to Southwest's formation, Mr. Wommack
was a self-employed independent oil and gas producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases
and the drilling of wells. Mr. Wommack graduated from the University of
North Carolina at Chapel Hill and received his law degree from the
University of Texas.
James N. Chapman has served as a director since April 19, 2002. Mr.
Chapman has been involved in the investment banking industry for 18 years,
presently acting as a capital markets and strategic planning consultant
with private and public companies across a range of industries, including
metals, mining, manufacturing, aerospace, airline, service and healthcare.
Prior to establishing an independent consulting practice, Mr. Chapman
worked for The Renco Group, Inc., a multi-billion private corporation in
New York, for which Mr. Chapman developed and implemented financing and
merger and acquisitions strategies for Renco's diverse portfolio of
companies. Prior to Renco, Mr. Chapman was a founding principal of
Fieldstone Private Capital Group, a capital markets advisory firm that he
joined upon its inception in August 1990. Prior to joining Fieldstone,
Mr. Chapman worked for Bankers Trust Company for six years, most recently
in the BT Securities Capital Markets area. Mr. Chapman received an MBA
degree with distinction from the Amos Tuck School at Dartmouth College and
was elected an Edward Tuck Scholar. He received his BA degree with
distinction magna cum laude, at Dartmouth College, was elected to Phi Beta
Kappa and was a Rufus Choate Scholar.
William P. Nicoletti has served as a director since April 19, 2002. Mr.
Nicoletti is Managing Director of Nicoletti & Company Inc., an investment
banking and financial advisory firm. He was formerly a senior officer and
head of the Energy Investment Banking Groups of E. F. Hutton & Company
Inc., Paine Webber, Incorporated and McDonald Investments Inc. Mr.
Nicoletti is Chairman of the board of directors of Russell-Stanley
Holdings, Inc., a manufacturer and marketer of steel and plastic industrial
containers. He is a director of Mark WestEnergy Partners, L.P., a business
engaged in the gathering and processing of natural gas and the
fractionation and storage of natural gas liquids. Mr. Nicoletti is also a
Director and Chairman of the Audit Committee of Star Gas Partners, L.P.,
the nation's largest retail distributor of home heating oil and a major
retail distributor of propane gas. Mr. Nicoletti is a graduate of Seton
Hall University and received an MBA degree from Columbia University
Graduate School of Business.
Joseph J. Radecki, Jr. has served as a director since April 19, 2002. Mr.
Radecki is currently a Managing Director in the Leveraged Finance Group of
CIBC World Markets where he is principally responsible for the firm's
financial restructuring and distressed situation advisory practice. Prior
to joining CIBC World Markets, Mr. Radecki was an Executive Vice President
and Director of the Financial Restructuring Group of Jefferies & Company,
Inc. from 1990 to 1998. From 1983 until 1990, Mr. Radecki was First Vice
President in the International Capital Markets Group at Drexel Burnham
Lambert, Inc., where he specialized in financial restructurings and
recapitalizations. Over the past fourteen years, Mr. Radecki has been
integrally involved in over 120 transactions totaling nearly $50 billion in
recapitalized securities. Mr. Radeki currently serves as a Director of
Wherehouse Entertainment, Inc., a music and video specialty retailer, and
RBX Corporation, a manufacturer of rubber and plastic foam and other
polymer products. He has previously served as Chairman of the Board of
American Rice, Inc., an international rice miller and marketer, as a member
of the Board of Directors of Service America Corporation, a national food
service management firm, Bucyrus International, Inc., a mining equipment
manufacturer, and ECO-Net, a non-profit engineering related network firm.
Mr. Radecki graduated magna cum laude in 1980 from Georgetown University
with a B.A. in Government.
Richard D. Rinehart has served as a director since April 19, 2002. Mr.
Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel
Resources, Inc. PetroCap, Inc. provides investment and merchant banking
services to a variety of clients active in the oil and gas industry.
Kestrel Resources, Inc. is a privately owned oil and gas operating company.
He served as Director of Coopers & Lybrand's Energy Systems and Services
Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to
joining Coopers & Lybrand, he was chief executive officer/founder of Dawn
Information Resources, Inc., formed in 1986 and acquired by Coopers &
Lybrand in early 1991. Mr. Rinehart served as CEO of Terrapet Energy
Corporation during the period 1982 through 1986. Prior to the formation of
Terrapet in 1982, he was employed as President of the Terrapet Division of
E.I. DuPont de Nemours and Company. Before its acquisition by DuPont, he
served as CEO and President of Terrapet Corp., a privately owned E & P
company. Before the formation of Terrapet Corp. in 1972, he was manager of
supplementary recovery methods and senior evaluation engineer with H. J.
Gruy and Associates, Inc., Dallas, Texas.
John M. White has served as a director since April 19, 2002. Mr. White is
currently an oil and gas analyst with BMO Nesbitt Burns, responsible for
Fixed Income research on oil, gas and energy companies. Prior to joining
BMO Nesbitt Burns in 1998, Mr. White was responsible for Fixed Income
research on the oil and gas industry at John S. Herold, Inc., an
independent oil and gas research and consulting firm. Mr. White's
experience also includes managing a portfolio of oil and gas loans for The
Bank of Nova Scotia, which included independent exploration and production
companies, oil service companies, gas pipelines, gas processors and
refiners. Prior to entering banking, Mr. White was with BP Exploration,
where he worked primarily in exploration and production.
Herbert C. Williamson, III has served as a director since April 19, 2002.
At present, Mr. Williamson is self-employed as a consultant. From March
2001 to March 2002 Mr. Williamson served as an investment banker with
Petrie Parkman & Co. From April 1999 to March 2001 Mr. Williamson served
as chief financial officer and from August 1999 to March 2001 as a director
of Merlon Petroleum Company, a private oil and gas company involved in
exploration and production in Egypt. Mr. Williamson served as executive
vice president, chief financial officer and director of Seven Seas
Petroleum, Inc., a publicly traded oil and gas exploration company, from
March 1998 to April 1999. From 1995 through April 1998, he served as
director in the Investment Banking Department of Credit Suisse First
Boston. Mr. Williamson served as vice chairman and executive vice
president of Parker and Parsley Petroleum Company, a publicly traded oil
and gas exploration company (now Pioneer Natural Resources Company) from
1985 through 1995.
Bill E. Coggin has served as Vice President and Chief Financial Officer
since joining the Managing General Partner in 1985. Previously, Mr. Coggin
was Controller for Rod Ric Corporation, an oil and gas drilling company,
and for C.F. Lawrence & Associates, a large independent oil and gas
operator. Mr. Coggin received a B.S. in Education and a B.A. in Accounting
from Angelo State University.
J. Steven Person has served as Vice President, Marketing since joining the
Managing General Partner in 1989. Mr. Person began in the investment
industry with Dean Witter in 1983. Prior to joining the Managing General
Partner, Mr. Person was a senior wholesaler with Capital Realty, Inc. While
at Capital Realty, he was involved in the syndication of mortgage based
securities through the major brokerage houses. Mr. Person received a
B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist
University.
Key Employees
Jon P. Tate, age 45, has served as Vice President, Land and Assistant
Secretary of the Managing General Partner since 1989. From 1981 to 1989,
Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent
oil and gas company, as land manager. Mr. Tate is a member of the Permian
Basin Landman's Association.
R. Douglas Keathley, age 47, has served as Vice President, Operations of
the Managing General Partner since 1992. Before joining us, Mr. Keathley
worked as a senior drilling engineer for ARCO Oil and Gas Company and in
similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.
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 $10,800 during 2002, 2001 and 2000 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 eleven percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns 22.0 limited partner units, or 1.7% limited partner interest. The
Managing General Partner total percentage interest ownership in the
Partnership is 12.7%.
No officer or director of the Managing General Partner owns Units in the
Partnership. H. H. Wommack, III, as the individual general partner of the
Partnership, owns a one percent interest as a general partner. The
officers and directors of the Managing General Partner are considered
beneficial owners of the limited partner units acquired by the Managing
General Partner by virtue of their status as such. Beneficial ownership is
determined in accordance with the rules of the Securities and Exchange
Commission and includes voting or investment power with respect to the
limited partner units. To our knowledge, except under applicable community
property laws or as otherwise indicated, the persons named in the table
have sole voting and sole investment control with regard to all limited
partner units beneficially owned. We are presenting ownership information
as of March 1, 2003. A list of beneficial owners of limited partner units,
acquired by the Managing General Partner, is as follows:
Amount and
Nature of Percen
t
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------- ---------- ------
-------------- -------------- ------ -----
Limited Partnership Southwest Royalties, Directly 1.7%
Interest Inc. Owns
Managing General 22.0 Units
Partner
407 N. Big Spring
Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly 1.7%
Interest Owns
Chairman of the 22.0 Units
Board,
President, and CEO
of Southwest
Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring
Street
Midland, TX 79701
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 2002, the Managing General Partner received $10,800 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 $12,100 for administrative overhead
attributable to operating such properties during 2002.
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 $700 for the year ended
December 31, 2002.
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 --
Independent Auditors Report
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.)
99.1 Certification pursuant to 18 U.S.C. Section 1350
99.2 Certification pursuant to 18 U.S.C. Section 1350
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2002.
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 28, 2003
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 By: /s/ James N.
Chapman
- --------------------------- ------------------------
- -------------------- -----------------------
H. H. Wommack, III, James N. Chapman,
Chairman of the Board, Director
President, Director and
Chief Executive Officer
Date: March 28, 2003 Date: March 28, 2003
By: /s/ William P. By: /s/ Joseph J.
Nicoletti Radecki, Jr.
- --------------------------- ------------------------
- -------------------- -----------------------
William P. Nicoletti, Joseph J. Radecki, Jr.,
Director Director
Date: March 28, 2003 Date: March 28, 2003
By: /s/ Richard D. By: /s/ John M. White
Rinehart
- --------------------------- ------------------------
- -------------------- -----------------------
Richard D. Rinehart, John M. White, Director
Director
Date: March 28, 2003 Date: March 28, 2003
By: /s/ Herbert C.
Williamson, III
- ---------------------------
- --------------------
Herbert C. Williamson, III,
Director
Date: March 28, 2003
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest
Developmental Drilling Fund 91-A, L.P.;
2. Based on my knowledge, this annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-A, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest
Developmental Drilling Fund 91-A, L.P.;
2. Based on my knowledge, this annual report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which
this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-A, L.P.
Exhibit Index
Item No. Description Page No.
Exhibit 99.1 Certification pursuant to 18 U.S.C. 39
Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Exhibit 99.2 Certification pursuant to 18 U.S.C. 40
Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
CERTIFICATION PURSUANT TO
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest
Developmental Drilling Fund 91-A, Limited Partnership (the
"Company") on Form 10-K for the period ending December 31, 2002
as filed with the Securities and Exchange Commission on the date
hereof (the "Report"), I, H.H. Wommack, III, Chief Executive
Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the
Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and results of
operation of the Company.
Date: March 28, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-A, L.P.
CERTIFICATION PURSUANT TO
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Developmental
Drilling Fund 91-A, Limited Partnership (the "Company") on Form
10-K for the period ending December 31, 2002 as filed with the
Securities and Exchange Commission on the date hereof (the
"Report"), I, Bill E. Coggin, Chief Financial Officer of the
Managing General Partner of the Company, certify, pursuant to 18
U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley
Act of 2002, that:
(3) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(4) The information contained in the Report fairly presents, in
all material respects, the financial condition and results of
operation of the Company.
Date: March 28, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Developmental Drilling Fund 91-A, L.P.