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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [Fee Required]
For the fiscal year ended December 31, 2000
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required]
For the transition period from to
Commission File Number 33-38511
Southwest Developmental Drilling Fund 91-A, L.P.
Exact name of registrant as specified in
its limited partnership agreement
Delaware 75-2387814
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300, Midland, Texas 79701
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (915) 686-9927
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
limited and general partner interests
Indicate by check mark whether registrant (1) has filed reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [x]
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 39. There is no
exhibit index.
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 6
3. Legal Proceedings 8
4. Submission of Matters to a Vote of Security Holders 8
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 9
6. Selected Financial Data 10
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 11
8. Financial Statements and Supplementary Data 18
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 34
Part III
10. Directors and Executive Officers of the Registrant 35
11. Executive Compensation 36
12. Security Ownership of Certain Beneficial Owners and
Management 36
13. Certain Relationships and Related Transactions 37
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 38
Signatures 39
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 92 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.
The year 2000 was a record year for crude oil prices. The world energy
markets witnessed a continuation of the 1999 recovery seeing prices in the
U.S. peak at $37 per barrel in September. Increasing demand and depleting
inventories appeared to be the motivators in crude's dramatic rise. At the
beginning of 2000, U.S. crude oil inventories were approximately 16% lower
than at the beginning of 1999 and summer vacationers made it through a
travel season that saw gasoline prices top $2 per gallon in some U.S.
markets. The lack of crude oil inventory in the U.S. was also magnified by
the colder than normal winter that much of the country experienced.
However, several production increases from OPEC coupled with President
Clinton's release of 30 million barrels of oil from the U.S. Strategic
Petroleum Reserve in September contributed to the slow in prices toward the
end of the year. After averaging $30 per barrel for the year and over $32
from August through November, oil prices closed out the year 2000 at $26.80
per barrel.
Tighter supplies, rising demand, and the return of more seasonal summer and
winter weather catapulted spot gas prices in 2000 to the highest levels
since the market was deregulated in the mid-1980's. Average monthly spot
prices rose an astounding 72.9% over 1999 levels to average $3.77/MMBTU.
The climb in prices was fairly steady throughout the year, with the first-
quarter spot prices averaging $2.44/MMBtu. After the winter season ended
with a huge storage deficit of 306 BCF, a combination of factors
contributed further to the upward trend in spot prices. As the summer
temperatures heated up and the rate of storage injections remained
sluggish, competition for gas supplies became fierce between power
generators and gas utilities attempting to refill storage. Spot prices
really took off in the fourth quarter as competition for storage gas in the
waning days of the refill season became supercharged. And then came weeks
of early heating-season cold, which caused gas utilities to scramble to
meet the heating loads. A year of record high prices was capped off in
December, with spot prices averaging $6.14/MMBtu, more than two-and-a-half
times the previous five-year December average of $2.43/MMBtu.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
2000 85% 15%
1999 86% 14%
1998 83% 17%
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. 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%. Two purchasers
accounted for 85% of the Partnership's total oil and gas production during
1999: Navajo Refining Company, Inc. for 52% and Scurlock Permian LLC for
33%. Three purchasers accounted for 93% of the Partnership's total oil and
gas production during 1998: Navajo Refining Company, Inc. for 45%, Scurlock
Permian Corporation 38% and Phillips 66 Natural Gas Company for 10%. 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,
2000 there were 92 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, 2000, 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 has not been any
significant changes in properties during 2000, 1999 and 1998.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and Location and Interest Wells Oil (bbls) Gas (mcf)
- ----------------- ------------ ----- ---------- ---------
Carson E 6/92 1 9,000 23,000
Ward County, 90%
Texas working
interest
Carson F #1 6/92 1 37,000 36,000
Ward County, 89%
Texas working
interest
*Ryder Scott Petroleum Engineers prepared the reserve and present value
data for the Partnership's existing properties as of January 1, 2001. The
reserve estimates were made in accordance with guidelines established by
the Securities and Exchange Commission pursuant to Rule 4-10(a) of
Regulation S-X. Such guidelines require oil and gas reserve reports be
prepared under existing economic and operating conditions with no
provisions for price and cost escalation except by contractual
arrangements.
The New York Mercantile Exchange price at December 31, 2000 of $26.80 was
used as the beginning basis for the oil price. Oil price adjustments from
$26.80 per barrel were made in the individual evaluations to reflect oil
quality, gathering and transportation costs. The results are an average
price received at the lease of $26.18 per barrel in the preparation of the
reserve report as of January 1, 2001.
In the determination of the gas price, the New York Mercantile Exchange
price at December 31, 2000 of $9.78 was used as the beginning basis. Gas
price adjustments from $9.78 per Mcf were made in the individual
evaluations to reflect BTU content, gathering and transportation costs and
gas processing and shrinkage. The results are an average price received at
the lease of $9.92 per Mcf in the preparation of the reserve report as of
January 1, 2001.
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 2000.
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 2000 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, 2000, no limited partner units were purchased by the Managing
General Partner. In 1999, 5 limited partner units were tendered to and
purchased by the Managing General Partner at an average base price of
$78.06 per unit. As of December 31, 1998, no limited partner units were
purchased by the Managing General Partner.
Number of Limited and General Partner Interest Holders
As of December 31, 2000, there were 103 holders of limited partner units
and no holders of general partner units in the Partnership.
Distributions
Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and
Agreement of Limited Partnership, "Net Cash Flow" is distributed to the
partners on a monthly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's drilling activities, less (i) General and
Administrative Costs, (ii) Operating Costs, and (iii) any reserves
necessary to meet current and anticipated needs of the Partnership,
including, but not limited to drilling cost overruns, as determined in the
sole discretion of the Managing General Partner."
During 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. During 1999, distributions were made totaling
$85,000, with $75,650 distributed to the investor partners and $9,350 to
the Managing General Partner. For the year ended December 31, 1999,
distributions of $66.10 per investor partner unit were made, based upon
1,144.5 investor partner units outstanding. During 1998, distributions
were made totaling $40,500, with $36,045 distributed to the investor
partners and $4,455 to the Managing General Partner. For the year ended
December 31, 1998, distributions of $31.49 per investor partner unit were
made, based upon 1,144.50 investor partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2000, 1999, 1998, 1997 and 1996 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
-----------------------------------------------------
Restated
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Revenues $ 162,884 252,026 172,847 307,526 480,994
Net income (loss) 58,242 119,990 (3,178) 126,704 278,970
Partners' share of
net income (loss):
Managing General
Partner 7,617 17,159 5,480 20,529 38,903
Investor partners 50,625 102,831 (8,658) 106,175 240,067
Investor partners'
net income (loss)
per unit 44.23 89.85 (7.57) 92.77 209.76
Investor partners'
cash distributions
per unit 94.12 66.10 31.49 225.51 196.74
Total assets $ 165,095 237,888 195,528 236,923 399,872
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 2001 to enhance production. Additional workovers may be performed
in the year 2003. The partnership may have an increase in production
volumes for the year 2003, otherwise, the partnership will most likely
experience the historical production decline of approximately 12% per year.
A. General Comparison of the Years Ended December 31, 2000 and 1999
The following table provides certain information regarding performance
factors for the years ended December 31, 2000 and 1999:
Year Ended
December 31, Percentage
Increase
2000 1999 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 29.88 16.88 77%
Average price per mcf of gas $ 3.82 1.81 111%
Oil production in barrels 4,600 12,800 (64%)
Gas production in mcf 6,600 19,540 (66%)
Gross oil and gas revenue $ 162,628 251,484 (35%)
Net oil and gas revenue $ 83,755 171,878 (51%)
Partnership distributions $ 121,035 85,000 42%
Limited partner distributions $ 107,721 75,650 42%
Per unit distribution to limited partners $ 94.12 66.10 42%
Number of limited partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $162,628 from $251,484
for the years ended December 31, 2000 and 1999, respectively, a decrease of
35%. The principal factors affecting the comparison of the years ended
December 31, 2000 and 1999 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the year ended December 31, 2000 as compared to the
year ended December 31, 1999 by 77%, or $13.00 per barrel, resulting in
an increase of approximately $59,800 in revenues. Oil sales represented
%85 of total oil and gas sales during the year ended December 31, 2000
as compared to 86% during the year ended December 31, 1999.
The average price for an mcf of gas received by the Partnership
increased during the same period by 111%, or $2.01 per mcf, resulting
in an increase of approximately $13,300 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $73,100. 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 8,200 barrels or 64% during the
year ended December 31, 2000 as compared to the year ended December 31,
1999, resulting in a decrease of approximately $138,400 in revenues.
Gas production decreased approximately 12,940 mcf or 66% during the
same period, resulting in a decrease of approximately $23,400 in
revenues.
The total decrease in revenues due to the change in production is
approximately $161,800. The sharp decrease in oil and gas production
is in relation to a settlement of royalty on the Dagger Draw Lease.
Production interest of approximately 5,000 bbls and 7,230 mcfs were
held in suspense from 1993 through 1999. These dollars were received
and recorded in the Partnership during the third quarter of 1999.
Production without the settlement would be a decrease of 25% for oil
and 29% for gas. This decrease was due to the occurrence of payout on
the Dagger Draw. Upon occurrence of payout the percentage of ownership
for the Partnership decrease significantly.
Costs and Expenses
Total costs and expenses decreased to $104,642 from $132,036 for the years
ended December 31, 2000 and 1999, respectively, a decrease of 21%. The
decrease is the result of lower lease operating costs, depletion expense
and general and administrative costs.
1. Lease operating costs and production taxes were 1% lower, or
approximately $700 less during the year ended December 31, 2000 as compared
to the year ended December 31, 1999.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
10% or approximately $1,700 during the year ended December 31, 2000 as
compared to the year ended December 31, 1999.
3. Depletion expense decreased to $11,000 for the year ended December 31,
2000 from $36,000 for the same period in 2000. This represents a
decrease of 69%. 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 to the decline in depletion expense between the
comparative periods was the increase in oil and gas prices of the 2001
reserves 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 $4,000 as of December 31, 1999.
B. General Comparison of the Years Ended December 31, 1999 and 1998
The following table provides certain information regarding performance
factors for the years ended December 31, 1999 and 1998:
Year Ended
December 31, Percentage
Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 16.88 12.74 32%
Average price per mcf of gas $ 1.81 1.60 13%
Oil production in barrels 12,800 11,300 13%
Gas production in mcf 19,540 17,800 10%
Gross oil and gas revenue $ 251,484 172,545 46%
Net oil and gas revenue $ 171,878 72,410 137%
Partnership distributions $ 85,000 40,500 110%
Limited partner distributions $ 75,650 36,045 110%
Per unit distribution to limited partners $ 66.10 31.49 110%
Number of limited partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues increased to $251,484 from $172,545
for the years ended December 31, 1999 and 1998, respectively, an increase
of 46%. The principal factors affecting the comparison of the years ended
December 31, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the year ended December 31, 1999 as compared to the
year ended December 31, 1998 by 32%, or $4.14 per barrel, resulting in
an increase of approximately $46,800 in revenues. Oil sales represented
86% of total oil and gas sales during the year ended December 31, 1999
as compared to 83% during the year ended December 31, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 13%, or $.21 per mcf, resulting in
an increase of approximately $3,700 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $50,500. The market price
for oil and gas has been extremely volatile over the past decade and
management expects a certain amount of volatility to continue in the
foreseeable future.
2. Oil production increased approximately 1,500 barrels or 13% during the
year ended December 31, 1999 as compared to the year ended December 31,
1998, resulting in an increase of approximately $25,300 in revenues.
Gas production increased approximately 1,740 mcf or 10% during the same
period, resulting in an increase of approximately $3,100 in revenues.
The total increase in revenues due to the change in production is
approximately $28,400. The increase in production is in relation to a
settlement of royalty on the Dagger Draw lease. Production interest of
approximately 5,000 bbls and 7,230 mcfs were held in suspense from 1993
through 1999. These dollars were received and recorded in the
Partnership during the third quarter of 1999. Production without the
settlement would have actually decreased oil by 31% and gas by 30%.
This decrease was due primarily to a decrease of the Partnerships
interest in the Dagger Draw lease in relation to a fairness letter.
Costs and Expenses
Total costs and expenses decreased to $132,036 from $176,025 for the years
ended December 31, 1999 and 1998, respectively, a decrease of 25%. The
decrease is the result of lower lease operating costs, depletion expense
and general and administrative costs.
2. Lease operating costs and production taxes were 21% lower, or
approximately $20,500 less during the year ended December 31, 1999 as
compared to the year ended December 31, 1998. The decrease in lease
operating costs are due primarily to workover expenses incurred during 1998
and the issuance of a fairness letter, which decreased the Partnership's
ownership percentage on the Dagger Draw.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
28% or approximately $6,500 during the year ended December 31, 1999 as
compared to the year ended December 31, 1998. The decrease of general
and administrative costs were due in part to additional accounting
costs incurred in 1998 in relation to the outsourcing of K-1 tax
package preparation and a change in auditors requiring opinions from
both the predecessors and successor auditors. Additionally, the
Managing General Partner in its effort to cut back on general and
administrative costs whenever and wherever possible was able to reduce
the cost of reserve reports and K-1 tax package preparation during
1999.
3. Depletion expense decreased to $36,000 for the year ended December 31,
1999 from $53,000 for the same period in 1999. This represents a
decrease of 32%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants.
A contributing factor to the decline in depletion expense between the
comparative periods was the impact of revisions of previous estimates
on reserves. Revisions of previous estimates can be attributed to the
changes in production performance, oil and gas price and production
costs. The impact of the revision would have decreased depletion
expense approximately $19,000 as of December 31, 1998.
C. Revenue and Distribution Comparison
Partnership net income (loss) for the years ended December 31, 2000, 1999
and 1998 was $58,242, $119,990 and $(3,178), respectively. Excluding the
effects of depreciation, depletion and amortization, net income for the
years ended December 31, 2000, 1999 and 1998 was $69,242, $155,990 and
$49,822, respectively. Correspondingly, Partnership distributions for the
years ended December 31, 2000, 1999 and 1998 were $121,035, $85,000 and
$40,500, respectively.
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. The sources for the 1999
distributions of $85,000 were oil and gas operations of approximately
$134,600 and the change in oil and gas properties of approximately $(900),
resulting in excess cash for contingencies or subsequent distributions.
The sources for the 1998 distributions of $40,500 were oil and gas
operations of approximately $67,300 and the change in oil and gas
properties of approximately $(21,800), resulting in excess cash for
contingencies or subsequent distributions.
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. Total distributions during the
year ended December 31, 1999 were $85,000 of which $75,650 was distributed
to the investor partners and $9,350 to the Managing General Partner. The
per unit distribution to investor partners during the same period was
$66.10. Total distributions during the year ended December 31, 1998 were
$40,500 of which $36,045 was distributed to the investor partners and
$4,455 to the Managing General Partner. The per unit distribution to
investor partners during the same period was $31.49.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,333,775 have been made to the partners. As of December 31, 2000,
$1,188,971 or $1,038.86 per investor partner unit, has been distributed to
the investor partners, representing a 104% return of the capital
contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
oil and gas properties. The Partnership anticipates the primary source of
cash to continue being from the oil and gas operations.
Cash flows provided by operating activities were approximately $78,700 in
2000 compared to $134,600 in 1999 and approximately $67,300 in 1998. The
primary source of the 2000 cash flow from operating activities was
profitable operations.
Cash flows used in investing activities were approximately $200 in 2000
compared to $900 in 1999 and approximately $21,800 in 1998. The principal
use of the 2000 cash flow from investing activities was additions to oil
and gas properties.
Cash flows used in financing activities were approximately $120,400 in 2000
compared to $88,200 in 1999 and approximately $38,200 in 1998. The only
use in the 2000 financing activities was the distributions to partners.
As of December 31, 2000, the Partnership had approximately $26,500 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenue generated from operations
are adequate to meet the needs of the Partnership.
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 19
Balance Sheets 20
Statements of Operations 21
Statement of Changes in Partners' Equity 22
Statements of Cash Flows 23
Notes to Financial Statements 25
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, 2000 and
1999, 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, 2000. 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, 2000 and 1999 and the results
of its operations and its cash flows for each of the years in the three-
year period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas
March 21, 2001
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2000 and 1999
2000 1999
---- ----
Assets
Current assets:
Cash and cash equivalents $ 14,338 56,196
Receivable from Managing General Partner 12,165 21,634
Distribution receivable - 617
- --------- ---------
Total current assets
26,503 78,447
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 1,098,592 1,098,441
Less accumulated depreciation,
depletion and amortization
960,000 949,000
- --------- ---------
Net oil and gas properties
138,592 149,441
- --------- ---------
$
165,095 227,888
========= =========
Liabilities and Partners' Equity
Partners' equity:
Managing General Partner $ 23,823 29,520
Investor partners 141,272 198,368
- --------- ---------
Total partners' equity
165,095 227,888
- --------- ---------
$
165,095 227,888
========= =========
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, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Revenues
Oil and gas sales $ 162,628 251,484 172,545
Interest income from operations 256 542 302
-------
- ------- -------
162,884
252,026 172,847
-------
- ------- -------
Expenses
Production 78,873 79,606 100,135
General and administrative 14,769 16,430 22,890
Depreciation, depletion and amortization 11,000 36,000 53,000
-------
- ------- -------
104,642
132,036 176,025
-------
- ------- -------
Net income (loss) $ 58,242 119,990 (3,178)
=======
======= =======
Net income (loss) allocated to:
Managing General Partner $ 7,617 17,159 5,480
=======
======= =======
Investor partners $ 50,625 102,831 (8,658)
=======
======= =======
Per investor partner unit $ 44.23 89.85 (7.57)
=======
======= =======
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, 2000, 1999 and 1998
Managing
General Investor
Partner Partners Total
------- -------- -----
Balance at December 31, 1997 $ 20,686 215,890 236,576
Net income (loss) 5,480 (8,658) (3,178)
Distributions (4,455) (36,045) (40,500)
-------
- -------- --------
Balance at December 31, 1998 21,711 171,187 192,898
Net income 17,159 102,831 119,990
Distributions (9,350) (75,650) (85,000)
-------
- -------- --------
Balance at December 31, 1999 29,520 198,368 227,888
Net income 7,617 50,625 58,242
Distributions (13,314) (107,721)(121,035)
-------
- -------- --------
Balance at December 31, 2000 $ 23,823 141,272 165,095
=======
======== ========
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, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 166,419 235,741 188,548
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(87,964) (101,686)(121,567)
Interest received 256 542 302
--------
- -------- --------
Net cash provided by operating activities 78,711 134,597
67,283
--------
- -------- --------
Cash flows from investing activities:
Additions to oil and gas properties (151) (873) (21,824)
--------
- -------- --------
Cash flows from financing activities:
Distributions to partners (120,418) (88,247) (38,217)
--------
- -------- --------
Net (decrease) increase in cash and cash
equivalents (41,858) 45,477 7,242
Beginning of period 56,196 10,719 3,477
--------
- -------- --------
End of period $ 14,338 56,196 10,719
========
======== ========
(continued)
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows, continued
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities:
Net income (loss) $ 58,242 119,990 (3,178)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 11,000 36,000
53,000
Decrease (increase) in receivables 3,791 (15,743) 16,003
Increase (decrease) in payables 5,678 (5,650) 1,458
-------
- ------- -------
Net cash provided by operating activities $ 78,711 134,597 67,283
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 91-A, L.P. was organized under
the laws of the state of Delaware on January 7, 1991 for the purpose
of drilling developmental and exploratory wells and to produce and
market crude oil and natural gas produced from such properties for a
term of 50 years, unless terminated at an earlier date as provided for
in the Partnership Agreement. The Partnership sells its oil and gas
production to a variety of purchasers with the prices it receives
being dependent upon the oil and gas economy. Southwest Royalties,
Inc. serves as the Managing General Partner. Revenues, costs and
expenses are allocated as follows:
Managing
General Investor
Partner Partners
-------- --------
Interest income on capital contributions - 100%
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and offering costs (1) - 100%
Syndication costs - 100%
Amortization of organization costs - 100%
Lease acquisition costs 1% 99%
Gain/loss on property disposition* 11% 89%
Operating and administrative costs*(2) 11% 89%
Depreciation, depletion and amortization
of oil and gas properties - 100%
Intangible drilling and development costs - 100%
All other costs* 11% 89%
*After the Investor Partners have received distributions totaling 150%
of their capital contributions, the allocation will change to 15%
Managing General Partner and 85% Investor Partners.
(1) All organization costs in excess of 4% of initial capital
contributions will be paid by the Managing General Partner and will be
treated as a capital contribution. The Partnership paid the Managing
General Partner an amount equal to 4% of initial capital contributions
for such organization costs.
(2) Administrative costs in any year which exceed 2% of capital
contributions shall be paid by the Managing General Partner and will
be treated as a capital contribution.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. Gain or loss on
the sale of oil and gas properties is not recognized unless
significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization
of oil and gas properties is computed under the units of revenue
method. Under the units of revenue method, depreciation, depletion
and amortization is computed on the basis of current gross revenues
from production in relation to future gross revenues, based on current
prices, from estimated production of proved oil and gas reserves.
Under the units of revenue method, the Partnership computes the
provision by multiplying the total unamortized cost of oil and gas
properties by an overall rate determined by dividing (a) oil and gas
revenues during the period by (b) the total future gross oil and gas
revenues as estimated by the Partnership's independent petroleum
consultants. It is reasonably possible that those estimates of
anticipated future gross revenues, the remaining estimated economic
life of the product, or both could be changed significantly in the
near term due to the potential fluctuation of oil and gas prices or
production. The depletion estimate would also be affected by this
change.
Should the net capitalized costs exceed the estimated present value of
oil and gas reserves, discounted at 10%, such excess costs would be
charged to current expense. As of December 31, 2000, 1999 and 1998
the net capitalized costs did not exceed the estimated present value
of oil and gas reserves.
Estimates and Uncertainties
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Syndication Costs
Syndication costs are accounted for as a reduction of partnership
equity.
Environmental Costs
The Partnership is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and
may require the Partnership to remove or mitigate the environmental
effects of the disposal or release of petroleum or chemical substances
at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Costs which
improve a property as compared with the condition of the property when
originally constructed or acquired and costs which prevent future
environmental contamination are capitalized. Expenditures that relate
to an existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for expenditures
of a non-capital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably
estimated.
Gas Balancing
The Partnership utilizes the sales method of accounting for gas-
balancing arrangements. Under this method the Partnership recognizes
sales revenue on all gas sold. As of December 31, 2000, 1999 and
1998, there were no significant amounts of imbalance in terms of units
and value.
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," the
Partnership's tax basis in its net oil and gas properties at December
31, 2000 and 1999 is $130,818 and $131,815, respectively, less than
that shown on the accompanying Balance Sheets in accordance with
generally accepted accounting principles.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Partnership considers
all highly liquid debt instruments purchased with a maturity of three
months or less to be cash equivalents. The Partnership maintains its
cash at one financial institution.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Number of Investor Partner Units
As of December 31, 2000, 1999 and 1998, there were 1,144.5 investor
partner units outstanding held by 103, 103 and 99 partners.
Concentrations of Credit Risk
The Partnership is subject to credit risk through trade receivables.
Although a substantial portion of its debtors' ability to pay is
dependent upon the oil and gas industry, credit risk is minimized due
to a large customer base. All partnership revenues are received by
the Managing General Partner and subsequently remitted to the
partnership and all expenses are paid by the Managing General Partner
and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair
value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
shall be further reduced by a risk factor discount of no more than one-
third (1/3) to be determined by the Managing General Partner in its
sole and absolute discretion.
The Partnership is subject to various federal, state and local
environmental laws and regulations, which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 2000, 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
4. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As is usual in the industry and as provided
for in the operating agreement for each respective oil and gas
property in which the Partnership has an interest, the operator is
paid an amount for administrative overhead attributable to operating
such properties, with such amounts to Southwest Royalties, Inc. as
operator approximating $11,400, $13,000 and $13,400 for the years
ended December 31, 2000, 1999 and 1998, respectively. In addition,
the Managing General Partner and certain officers and employees may
have an interest in some of the properties that the Partnership also
participates.
Certain subsidiaries or affiliates of the Managing General Partner
perform various oilfield services for properties in which the
Partnership owns an interest. Such services aggregated approximately
$4,300, $7,300 and $3,200 for the years ended December 31, 2000, 1999
and 1998, respectively, and the Managing General Partner believes that
these costs are comparable to similar charges paid by the Partnership
to unrelated third parties.
Southwest Royalties, Inc., the Managing General Partner, was paid
$10,800 in 2000, $11,000 in 1999 and $10,793 in 1998 for indirect
general and administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $12,200 and $21,600 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2000 and 1999, respectively.
In addition, a director and officer of the Managing General Partner is
a partner in a law firm, with such firm providing legal services. The
Partnership had no legal services for the years ended December 31,
2000, 1999 and 1998, respectively.
5. 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. 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%. Two purchasers accounted for 85% of the
Partnership's total oil and gas production during 1999: Navajo
Refining Company, Inc. for 52% and Scurlock Permian LLC for 33%.
Three purchasers accounted for 93% of the Partnership's total oil and
gas production during 1998: Navajo Refining Company, Inc. for 45%,
Scurlock Permian Corporation 38% and Phillips 66 Natural Gas Company
for 10%. 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
6. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil (bbls) Gas (mcf)
---------- ---------
Proved developed and undeveloped
reserves -
January 1, 1998 55,000 70,000
Revisions of estimates in place 2,000 16,000
Production (11,000) (18,000)
------- -------
December 31, 1998 46,000 68,000
Revisions of estimates in place 11,000 13,000
Production (13,000) (20,000)
------- -------
December 31, 1999 44,000 61,000
Revisions of estimates in place 10,000 15,000
Production (5,000) (7,000)
------- -------
December 31, 2000 49,000 69,000
======= =======
Proved developed reserves -
December 31, 1998 46,000 68,000
======= =======
December 31, 1999 44,000 61,000
======= =======
December 31, 2000 49,000 69,000
======= =======
All of the Partnership's reserves are located within the continental
United States.
*Ryder Scott Petroleum Engineers prepared the reserve and present
value data for the Partnership's existing properties as of January 1,
2001. The reserve estimates were made in accordance with guidelines
established by the Securities and Exchange Commission pursuant to Rule
4-10(a) of Regulation S-X. Such guidelines require oil and gas
reserve reports be prepared under existing economic and operating
conditions with no provisions for price and cost escalation except by
contractual arrangements.
The New York Mercantile Exchange price at December 31, 2000 of $26.80
was used as the beginning basis for the oil price. Oil price
adjustments from $26.80 per barrel were made in the individual
evaluations to reflect oil quality, gathering and transportation
costs. The results are an average price received at the lease of
$26.18 per barrel in the preparation of the reserve report as of
January 1, 2001.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil and Gas Reserves (unaudited) - continued
In the determination of the gas price, the New York Mercantile
Exchange price at December 31, 2000 of $9.78 was used as the beginning
basis. Gas price adjustments from $9.78 per Mcf were made in the
individual evaluations to reflect BTU content, gathering and
transportation costs and gas processing and shrinkage. The results
are an average price received at the lease of $9.92 per Mcf in the
preparation of the reserve report as of January 1, 2001.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing and proved developed non-producing. All of the proved
reserves are included in the engineering reports which evaluate the
Partnership's present reserves
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2000, 1999 and 1998 is
presented below:
2000 1999 1998
---- ---- ----
Future cash inflows $ 1,966,000 1,179,000 602,000
Production and development costs 1,129,000 686,000 374,000
--------- --------- ---------
Future net cash flows 837,000 493,000 228,000
10% annual discount for estimated
timing of cash flows 275,000 142,000 (47,000)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 562,000 351,000 275,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2000, 1999 and 1998 are as follows:
2000 1999 1998
---- ---- ----
Sales of oil and gas produced,
net of production costs $ (84,000) (172,000) (73,000)
Changes in prices and production costs 157,000 167,000
(339,000)
Changes of production rates
(timing) and others (28,000) (20,000) 169,000
Revisions of previous
quantities estimates 116,000 89,000 23,000
Changes in estimated future
development costs 15,000 (16,000) -
Accretion of discount 35,000 28,000 45,000
Discounted future net
cash flows -
Beginning of year 351,000 275,000 450,000
--------- -------- ---------
End of year $ 562,000 351,000 275,000
========= ======== =========
Future net cash flows were computed using year-end prices and costs
that related to existing proved oil and gas reserves in which the
Partnership has mineral interests.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Selected Quarterly Financial Results - (unaudited)
Quarter
----------------------------------------------
First Second Third Fourth
------ ------- ------ ------
2000:
Total revenues $ 36,095 43,158 50,190 33,441
Total expenses 27,399 23,166 26,858 27,219
Net income 8,696 19,992 23,332 6,222
Net income per limited
partners unit 6.38 15.35 17.76 4.74
1999:
Total revenues $ 39,183 45,317 127,659 39,867
Total expenses 28,837 26,757 36,724 39,718
Net income 10,346 18,560 90,935 149
Net income (loss) per limited
partners unit 7.37 13.99 69.91 (1.42)
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. The present directors of the Managing General Partner
have served in their capacity since the Company's formation in 1983.
Name Age Position
- -------------------- --- -----------------------------------
- -------
H. H. Wommack, III 45 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 44 Secretary and Director
Bill E. Coggin 46 Vice President and Chief
Financial Officer
J. Steven Person 42 Vice President, Marketing
Paul L. Morris 59 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive
Officer, Treasurer, principal stockholder and a director of the Managing
General Partner, and has served as its President since the Company's
organization in August, 1983. Prior to the formation of the Company, Mr.
Wommack was a self-employed independent oil producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases,
and the drilling of exploratory and developmental oil and gas wells. Mr.
Wommack holds a J.D. degree from the University of Texas from which he
graduated in 1980, and a B.A. from the University of North Carolina in
1977.
H. Allen Corey, a founder of the Managing General Partner, has served as
the Managing General Partner's secretary and a director since its
inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew
pub restaurant chain based in the Southeast. Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga, Tennessee. He is currently of counsel to the law firm of
Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga,
Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University
Law School and B.A. degree from the University of North Carolina at Chapel
Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with
the Managing General Partner since 1985. Mr. Coggin was Controller for Rod
Ric Corporation of Midland, Texas, an oil and gas drilling company, during
the latter part of 1984. He was Controller for C.F. Lawrence & Associates,
Inc., an independent oil and gas operator also of Midland, Texas during the
early part of 1984. Mr. Coggin taught public school for four years prior
to his business experience. Mr. Coggin received a B.S. in Education and a
B.B.A. in Accounting from Angelo State University.
J. Steven Person, Vice President, Marketing, assumed his responsibilities
with the Managing General Partner as National Marketing Director in 1989.
Prior to joining the Managing General Partner, Mr. Person served as Vice
President of Marketing for CRI, Inc., and was associated with Capital
Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor
University in 1982 and an M.B.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings,
Inc. since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States. Prior to
his position with Wagner & Brown, Mr. Morris served as President of Banner
Energy and in various managerial positions with the Columbia Gas System,
Inc.
Key Employees
Jon P. Tate, Vice President, Land and Assistant Secretary, age 43, assumed
his responsibilities with the Managing General Partner in 1989. Prior to
joining the Managing General Partner, Mr. Tate was employed by C.F.
Lawrence & Associates, Inc., an independent oil and gas company, as Land
Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin
Landman's Association and American Association of Petroleum Landmen. Mr.
Tate received his B.B.S. degree from Hardin-Simmons University.
R. Douglas Keathley, Vice President, Operations, age 45, assumed his
responsibilities with the Managing General Partner as a Production Engineer
in October, 1992. Prior to joining the Managing General Partner, Mr.
Keathley was employed for four (4) years by ARCO Oil & Gas Company as
senior drilling engineer working in all phases of well production (1988-
1992), eight (8) years by Reading & Bates Petroleum Company as senior
petroleum engineer responsible for drilling (1980-1988) and two (2) years
by Tenneco Oil Company as drilling engineer responsible for all phases of
drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum
Engineering in 1977 from the University of Oklahoma.
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 2000, $11,000 during 1999 and $10,793 during 1998
as an annual administrative fee for reimbursement of indirect general and
administrative costs.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no limited partners who own of record, or are known by the
Managing General Partner to beneficially own, more than five percent of the
Partnership's limited partnership interests.
The Managing General Partner owns an 11 percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns 5 limited partner units, or .4% limited partner interest. The
Managing General Partner total percentage interest ownership in the
Partnership is 11.4%.
No officer or director of the Managing General Partner owns Units in the
Partnership. There are no arrangements known to the Managing General
Partner which may at a subsequent date result in a change of control of the
Partnership.
Item 13. Certain Relationships and Related Transactions
In 2000, 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 $11,400 for administrative overhead
attributable to operating such properties during 2000.
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 $4,300 for the year ended
December 31, 2000.
The law firm of Baker, Donelson, Bearman & Caldwell, of which H. Allen
Corey, an officer and director of the Managing General Partner, is a
partner, is counsel to the Partnership. Baker, Donelson, Bearman & Caldwell
provided services totaling approximately. There were no legal services for
the year ended December 31, 2000, which constitutes an immaterial portion
of that firm's business.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
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.)
27 Financial Data Schedule
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2000.
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 30, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III
-----------------------------------
H. H. Wommack, III, Chairman of the
Board, President, Chief Executive
Officer, Treasurer and Director
Date: March 30, 2001
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 30, 2001