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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, 2001
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 5
3. Legal Proceedings 7
4. Submission of Matters to a Vote of Security Holders 7
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 8
6. Selected Financial Data 9
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 10
8. Financial Statements and Supplementary Data 18
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 33
Part III
10. Directors and Executive Officers of the Registrant 34
11. Executive Compensation 35
12. Security Ownership of Certain Beneficial Owners and
Management 35
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 89 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.
For nearly nine months, despite the fears of a global recession, crude oil
prices held steady between $26 and $28 per barrel due in part to a series
of OPEC and non-OPEC production cuts. Then, following what has become
known simply as "9-11", crude prices plunged immediately to $22 and
gradually fell to below $18 per barrel. Slower demand across the U.S.
caused by the threat of recession and warmer than expected weather also led
to declining prices in the latter half of 2001. However, the oil cartel
and other non-member countries agreed for the fourth time since February to
curb output in an effort to stabilize prices. Crude oil contracts trading
on the NYMEX closed the year at approximately $20 per barrel.
Spot prices in 2001 climbed to their highest levels ever, with the yearly
average price nationwide reaching $4.14/MMBtu, up 9.77% from the 2000
average of $3.77/MMBtu. Prices reached their zenith in the first quarter
of 2001 before beginning a steady decline throughout the remainder of the
year. The terrorist attacks of September 11 knocked the New York
Mercantile Exchange out of the market for several days and shook the spot
marketplace into a maintenance mode. As companies measured the impact of
the attacks on the U.S. economy, spot prices deteriorated further. In the
fourth quarter, prices bottomed out for the year with the three-month
average falling to $2.31/MMBtu. As for 2002, record-high storage levels
and the expectation of a flat economy through the first half of the year
are leading industry experts to predict prices to average $2.05/MMBtu,
remaining above the $2.00 per MMBtu level for a 5th consecutive year.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
2001 82% 18%
2000 85% 15%
1999 86% 14%
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
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%. 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%. 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,
2001 there were 89 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, 2001, 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 2001, 2000 and 1999.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and Location and Interest Wells Oil (bbls) Gas (mcf)
- ----------------- ------------ ----- ---------- ---------
Carson F #1 6/92 1 23,000 25,000
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, 2002. 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, 2002 are an average price of $18.98 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, 2002 are an
average price of $2.28 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 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.
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 2001 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. 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. 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.
Number of Limited and General Partner Interest Holders
As of December 31, 2001, 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 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. 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.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2001, 2000, 1999, 1998 and 1997 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
-----------------------------------------------------
Restated
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Revenues $ 139,286 162,884 252,026 172,847 307,526
Net income (loss) 30,325 58,242 119,990 (3,178) 126,704
Partners' share of
net income (loss):
Managing General
Partner 5,536 7,617 17,159 5,480 20,529
Investor partners 24,789 50,625 102,831 (8,658) 106,175
Investor partners'
net income (loss)
per unit 21.66 44.23 89.85 (7.57) 92.77
Investor partners'
cash distributions
per unit 48.39 94.12 66.10 31.49 225.51
Total assets $ 133,225 165,095 237,888 195,528 236,923
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 2002 to enhance production. The partnership will most likely
experience the historical production decline of approximately 8% 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.
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.
A. 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
December 31, Percentage
Increase
2001 2000 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 25.84 29.88 (14%)
Average price per mcf of gas $ 4.41 3.82 15%
Oil production in barrels 4,440 4,600 (3%)
Gas production in mcf 5,540 6,600 (16%)
Gross oil and gas revenue $ 139,132 162,628 (14%)
Net oil and gas revenue $ 65,516 83,755 (22%)
Partnership distributions $ 62,234 121,035 (49%)
Limited partner distributions $ 55,388 107,721 (49%)
Per unit distribution to limited partners $ 48.39 94.12 (49%)
Number of limited partner units 1,144.5 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 to 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.
B. 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.
2. 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.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2001, 2000 and 1999
was $30,325, $58,242 and $119,990, respectively. Excluding the effects of
depreciation, depletion and amortization, net income for the years ended
December 31, 2001, 2000 and 1999 was $50,325, $69,242 and $155,990,
respectively. Correspondingly, Partnership distributions for the years
ended December 31, 2001, 2000 and 1999 were $62,234, $121,035 and $85,000,
respectively.
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. 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.
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.
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.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,396,009 have been made to the partners. As of December 31, 2001,
$1,244,359 or $1,087.25 per investor partner unit, has been distributed to
the investor partners, representing a 109% 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 $60,400 in
2001 compared to $78,700 in 2000 and approximately $134,600 in 1999. The
primary source of the 2001 cash flow from operating activities was
profitable operations.
Cash flows used in investing activities were approximately $200 in 2001
compared to $200 in 2000 and approximately $900 in 1999. The principal use
of the 2001 cash flow from investing activities was additions to oil and
gas properties.
Cash flows used in financing activities were approximately $62,200 in 2001
compared to $120,400 in 2000 and approximately $88,200 in 1999. The only
use in the 2001 financing activities was the distributions to partners.
As of December 31, 2001, the Partnership had approximately $14,400 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenue generated from operations
are adequate to meet the needs of the Partnership.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
$50.0 million and $123.7 million of principal due in August of 2003 and
October of 2004, respectively. The Managing General Partner will incur
approximately $17.6 million in interest payments in 2002 on its debt
obligations. Due to the depressed commodity prices experienced during the
last quarter of 2001, the Managing General Partner is experiencing
difficulty in generating sufficient cash flow to meet its obligations and
sustain its operations. The Managing General Partner is currently in the
process of renegotiating the terms of its various obligations with its
creditors and/or attempting to seek new lenders or equity investors.
Additionally, the Managing General Partner would consider disposing of
certain assets in order to meet its obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the lenders will agree to
a course of action consistent with the Managing General Partners
requirements in restructuring the obligations. Even if such agreement is
reached, it may require approval of additional lenders, which is not
assured. Furthermore, there can be no assurance that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Under current circumstances, the Managing General
Partner's ability to continue as a going concern depends upon its ability
to (1) successfully restructure its obligations or obtain additional
financing as may be required, (2) maintain compliance with all debt
covenants, (3) generate sufficient cash flow to meet its obligations on a
timely basis, and (4) achieve satisfactory levels of future earnings. If
the Managing General Partner is unsuccessful in its efforts, it may be
unable to meet its obligations making it necessary to undertake such other
actions as may be appropriate to preserve asset values. Upon the
occurrence of any event of dissolution by the Managing General Partner, the
holders of a majority of limited partnership interests may, by written
agreement, elect to continue the business of the Partnership in the
Partnership's name, with Partnership property, in a reconstituted
partnership under the terms of the partnership agreement and to designate a
successor Managing General Partner.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No.133, "Accounting
for Derivative Instruments and Hedging Activities." SFAS No. 133, as
amended by SFAS No. 138, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded
in other contracts and for hedging activities. Assessment by the Managing
General Partner revealed this pronouncement to have no impact on the
partnerships.
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.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets." This pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed" and eliminates the requirement of
Statement 121 to allocate goodwill to long-lived assets to be tested for
impairment. The provisions of this statement are effective for financial
statements issued for fiscal years beginning after December 15, 2001, and
interim periods within those fiscal years. The Managing General Partner is
currently assessing the impact to 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 18
Balance Sheets 19
Statements of Operations 20
Statement of Changes in Partners' Equity 21
Statements of Cash Flows 22
Notes to Financial Statements 24
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, 2001 and
2000, 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, 2001. 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, 2001 and 2000 and the results
of its operations and its cash flows for each of the years in the three
year period ended December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas
March 10, 2002
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2001 and 2000
2001 2000
---- ----
Assets
------
Current assets:
Cash and cash equivalents $ 12,402 14,338
Receivable from Managing General Partner 2,047 12,165
- --------- ---------
Total current assets
14,449 26,503
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 1,098,776 1,098,592
Less accumulated depreciation,
depletion and amortization
980,000 960,000
- --------- ---------
Net oil and gas properties
118,776 138,592
- --------- ---------
$
133,225 165,095
========= =========
Liabilities and Partners' Equity
--------------------------------
Current liabilities:
Distribution payable $ 39 -
- --------- ---------
Partners' equity:
Managing General Partner 22,513 23,823
Investor partners 110,673 141,272
- --------- ---------
Total partners' equity
133,186 165,095
- --------- ---------
$
133,225 165,095
========= =========
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 Operations
For the years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Revenues
--------
Oil and gas sales $ 139,132 162,628 251,484
Interest income from operations 154 256 542
-------
- ------- -------
139,286
162,884 252,026
-------
- ------- -------
Expenses
--------
Production 73,616 78,873 79,606
General and administrative 15,345 14,769 16,430
Depreciation, depletion and amortization 20,000 11,000 36,000
-------
- ------- -------
108,961
104,642 132,036
-------
- ------- -------
Net income $ 30,325 58,242 119,990
=======
======= =======
Net income allocated to:
Managing General Partner $ 5,536 7,617 17,159
=======
======= =======
Investor partners $ 24,789 50,625 102,831
=======
======= =======
Per investor partner unit $ 21.66 44.23 89.85
=======
======= =======
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, 2001, 2000 and 1999
Managing
General Investor
Partner Partners Total
------- -------- -----
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
Net income 5,536 24,789 30,325
Distributions (6,846) (55,388) (62,234)
-------
- -------- --------
Balance at December 31, 2001 $ 22,513 110,673 133,186
=======
======== ========
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, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 152,656 166,419 235,741
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(92,367) (87,964)(101,686)
Interest received 154 256 542
--------
- -------- --------
Net cash provided by operating activities 60,443 78,711
134,597
--------
- -------- --------
Cash flows used in investing activities:
Additions to oil and gas properties (184) (151) (873)
--------
- -------- --------
Cash flows used in financing activities:
Distributions to partners (62,195) (120,418) (88,247)
--------
- -------- --------
Net (decrease) increase in cash and cash
equivalents (1,936) (41,858) 45,477
Beginning of period 14,338 56,196 10,719
--------
- -------- --------
End of period $ 12,402 14,338 56,196
========
======== ========
(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, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Reconciliation of net income to net
cash provided by operating activities:
Net income $ 30,325 58,242 119,990
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 20,000 11,000
36,000
Decrease (increase) in receivables 13,524 3,791 (15,743)
(Decrease) increase in payables (3,406) 5,678 (5,650)
-------
- ------- -------
Net cash provided by operating activities $ 60,443 78,711 134,597
=======
======= =======
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.
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.
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
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, 2001, 2000 and 1999
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.
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, 2001, 2000 and
1999, 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, 2001 and 2000 is $113,822 and $130,818, 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, 2001, 2000 and 1999, there were 1,144.5 investor
partner units outstanding held by 102, 103 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
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No.133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS
No. 133, as amended by SFAS No. 138, establishes accounting and
reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging
activities. Assessment by the Managing General Partner revealed this
pronouncement to have no impact on the partnerships.
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.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for
the Impairment or Disposal of Long-Lived Assets." This pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed" and eliminates the
requirement of Statement 121 to allocate goodwill to long-lived assets
to be tested for impairment. The provisions of this statement are
effective for financial statements issued for fiscal years beginning
after December 15, 2001, and interim periods within those fiscal
years. The Managing General Partner is currently assessing the impact
to 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 $50.0 million and $123.7 million of principal due in August of
2003 and October of 2004, respectively. The Managing General Partner
will incur approximately $17.6 million in interest payments in 2002 on
its debt obligations. Due to the depressed commodity prices
experienced during the last quarter of 2001, the Managing General
Partner is experiencing difficulty in generating sufficient cash flow
to meet its obligations and sustain its operations. The Managing
General Partner is currently in the process of renegotiating the terms
of its various obligations with its creditors and/or attempting to
seek new lenders or equity investors. Additionally, the Managing
General Partner would consider disposing of certain assets in order to
meet its obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the lenders will
agree to a course of action consistent with the Managing General
Partners requirements in restructuring the obligations. Even if such
agreement is reached, it may require approval of additional lenders,
which is not assured. Furthermore, there can be no assurance that the
sales of assets can be successfully accomplished on terms acceptable
to the Managing General Partner. Under current circumstances, the
Managing General Partner's ability to continue as a going concern
depends upon its ability to (1) successfully restructure its
obligations or obtain additional financing as may be required, (2)
maintain compliance with all debt covenants, (3) generate sufficient
cash flow to meet its obligations on a timely basis, and (4) achieve
satisfactory levels of future earnings. If the Managing General
Partner is unsuccessful in its efforts, it may be unable to meet its
obligations making it necessary to undertake such other actions as may
be appropriate to preserve asset values. Upon the occurrence of any
event of dissolution by the Managing General Partner, the holders of a
majority of limited partnership interests may, by written agreement,
elect to continue the business of the Partnership in the Partnership's
name, with Partnership property, in a reconstituted partnership under
the terms of the partnership agreement and to designate a successor
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 Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Commitments and Contingent Liabilities - continued
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, 2001, 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.
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 $11,800,
$11,400 and $13,000 for the years ended December 31, 2001, 2000 and
1999, 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
$1,100, $4,300 and $7,300 for the years ended December 31, 2001, 2000
and 1999, respectively.
Southwest Royalties, Inc., the Managing General Partner, was paid
$10,800 in 2001 and 2000 and $11,000 in 1999 for indirect general and
administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $2,000 and $12,200 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2001 and 2000, 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,
2001, 2000 and 1999, respectively.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
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. 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%. 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%. 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.
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil (bbls) Gas (mcf)
---------- ---------
Proved developed and undeveloped
reserves -
January 1, 1999 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
Revisions of estimates in place (20,000) (32,000)
Production (4,000) (6,000)
------- -------
December 31, 2001 25,000 31,000
======= =======
Proved developed reserves -
December 31, 1999 44,000 61,000
======= =======
December 31, 2000 49,000 69,000
======= =======
December 31, 2001 25,000 31,000
======= =======
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,
2002. 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.
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
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, 2002 are an average price of
$18.98 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, 2002 are an average price of $2.28 per Mcf.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing and proved developed non-producing. All of the proved
reserves are included in the engineering reports which evaluate the
Partnership's present reserves
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is
presented below:
2001 2000 1999
---- ---- ----
Future cash inflows $ 553,000 1,966,000 1,179,000
Production and development costs 395,000 1,129,000 686,000
--------- --------- ---------
Future net cash flows 158,000 837,000 493,000
10% annual discount for estimated
timing of cash flows 37,000 275,000 142,000
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 121,000 562,000 351,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2001, 2000 and 1999 are as follows:
2001 2000 1999
---- ---- ----
Sales of oil and gas produced,
net of production costs $ (66,000) (84,000) (172,000)
Changes in prices and production costs (346,000) 157,000
167,000
Changes of production rates
(timing) and others 16,000 (28,000) (20,000)
Revisions of previous
quantities estimates (101,000) 116,000 89,000
Changes in estimated future
development costs - 15,000 (16,000)
Accretion of discount 56,000 35,000 28,000
Discounted future net
cash flows -
Beginning of year 562,000 351,000 275,000
--------- -------- ---------
End of year $ 121,000 562,000 351,000
========= ======== =========
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
8. Selected Quarterly Financial Results - (unaudited)
Quarter
----------------------------------------------
First Second Third Fourth
------ ------- ------ ------
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
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
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 46 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 45 Secretary and Director
Bill E. Coggin 47 Vice President and Chief
Financial Officer
J. Steven Person 43 Vice President, Marketing
Paul L. Morris 60 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 44, 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 46, 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 2001 and 2000 and $11,000 during 1999 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 22.0 limited partner units, or 1.9% 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. A list of beneficial
owners of limited partner units, acquired by the Managing General Partner,
is as follows:
Amount and
Nature of Percent
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------------- --------------- -------
Limited Partnership Southwest Royalties, Inc. Directly Owns 1.9%
Interest Managing General Partner 22.0 Units
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns 1.9%
Interest Chairman of the Board, 22.0 Units
President, CEO, Treasurer
and Director of Southwest
Royalties, Inc., the
Managing General Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. Allen Corey Indirectly Owns 1.9%
Interest Secretary and Director of 22.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
633 Chestnut Street
Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns 1.9%
Interest Vice President and CFO of 22.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns 1.9%
Interest Vice President, Marketing of 22.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns 1.9%
Interest Director, of Southwest 22.0 Units
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 2001, 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 $11,800 for administrative overhead
attributable to operating such properties during 2001.
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 $1,100 for the year ended
December 31, 2001.
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, 2001, 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.)
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2001.
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 29, 2002
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 29, 2002
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 29, 2002