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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 92-A, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2387816
(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 19
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 92-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on May 5,
1992. The offering of limited and general partner interests began August
11, 1992 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 December 28, 1992, with the offering of limited
and general partner interests concluding December 31, 1992, with total
investor partner contributions of $1,407,000. The Managing General Partner
made a contribution to the capital of the Partnership at the conclusion of
the offering period in an amount equal to 1% of its net capital
contributions. The Managing General Partner contribution was $12,030, for
total capital contributions of $1,419,030. 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 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 leasehold
interests upon which drilling would be performed, and the marketing of
future anticipated production from such properties. The Partnership has no
employees.
Principal Products, Marketing and Distribution
The Partnership has acquired undeveloped 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 will be 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 72% 28%
2000 78% 22%
1999 77% 23%
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 of 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
anticipates that it will be able to sell all of the expected future
production of natural gas, either through contracts or on the spot market
at the then prevailing spot market price.
Customer Dependence
No material portion of the Partnership's business is dependent on a single
purchaser, or a very few purchasers, where the loss of one would have a
material adverse impact on the Partnership. Three purchasers accounted for
93% of the Partnership's total oil and gas production during 2001: Plains
Marketing LP for 58%, Duke Energy Field Services for 21% and Navajo
Refining Company, Inc. for 14%. Three purchasers accounted for 94% of the
Partnership's total oil and gas production during 2000: Plains Marketing LP
for 63%, Navajo Refining Company, Inc. for 16% and Duke Energy Transport
and Trad. for 15%. Three purchasers accounted for 95% of the Partnership's
total oil and gas production during 1999: Scurlock Permian LLC for 59%,
Duke Energy Transport and Trad. for 20% and Navajo Refining Company, Inc.
for 16%. 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 drilling prospects and drilling activities, 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.
Regulation
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 future expected 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, landmen 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 leasehold was to be
acquired, the Managing General Partner considered such criteria as
estimated drilling costs, estimated oil and gas reserves, estimated cash
flow from the sale of future production, present and future prices of oil
and gas, the extent of undeveloped and unproved reserves and the
availability of markets.
As of December 31, 2001, the Partnership possessed an interest in oil and
gas properties located in Ward County of Texas and Lea and Eddy Counties of
New Mexico. These properties consist of various interests in 9 wells.
Due to the Partnership's objective of maintaining current operations
without engaging in the additional 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 properties in which the Partnership has an
interest:
Date
Purchased No. of Proved Reserves*
Name and Location and Interest Wells Oil (bbls) Gas (mcf)
Mobil Fee H #1 12/92 at 1 46,000 189,000
Ward County, 100%
Texas working
interest
*Ryder Scott Petroleum Engineer 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 $18.90 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 $2.34 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.
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. 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.
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 Nations Bank, 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, 2001, no limited partner units were purchased by the Managing
General Partner. In 2000, 5 limited partner units were tendered to and
purchased by the Managing General Partner at an average base price of
$181.86 per unit. As of December 31, 1999, no limited partner units were
purchased by the Managing General Partner.
Number of Limited and General Partner Interest Holders
As of December 31, 2001, there were 105 holders of limited partner units.
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, quarterly distributions were made totaling $208,798, with
$185,830 distributed to the investor partners and $22,968 to the Managing
General Partners. For the year ended December 31, 2001, distributions of
$132.08 per investor partner unit were made, based upon 1,407 investor
partner units outstanding. During 2000, quarterly distributions were made
totaling $224,640, with $199,930 distributed to the investor partners and
$24,710 to the Managing General Partners. For the year ended December 31,
2000, distributions of $142.10 per investor partner unit were made, based
upon 1,407 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 Partners. For the year ended
December 31, 1999, distributions of $53.77 per investor partner unit were
made, based upon 1,407 investor partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the year ended December 31, 2001,
2000, 1999, 1998 and 1997 should be read in conjunction with the financial
statements included in Item 8:
Year ended December 31,
------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Revenues $ 333,192 372,553 249,965 201,370 335,791
Net income (loss) 160,893 217,640 112,767(331,847) 93,437
Partners' share of net
income (loss):
Managing General
Partner 20,338 25,590 14,274 6,863 19,601
Investor partners 140,555 192,050 98,493(338,710) 73,836
Investor partners' net
income (loss) per unit 99.90 136.50 70.00 (240.73)
52.48
Investor partners' cash
distributions per unit 132.08 142.10 53.77 58.32
129.99
Total assets $ 231,369 279,195 286,195 258,508 682,573
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 92-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on May 5,
1992. The offering of limited and general partner interests began August
11, 1992 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 December 28, 1992, with the offering of limited
and general partner interests concluding December 31, 1992, with total
investor partner contributions of $1,407,000. The Managing General Partner
made a contribution to the capital of the Partnership at the conclusion of
the offering period in an amount equal to 1% of its net capital
contributions. The Managing General Partner contribution was $12,030.
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
to enhance production. The partnership will most likely experience the
historical production decline of approximately 6% 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.
Results of Operations
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 Percentage
December 31, Increase
2001 2000 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 25.25 29.73 (15%)
Average price per mcf of gas $ 4.08 3.98 3%
Oil production in barrels 9,460 9,800 (3%)
Gas production in mcf 23,000 20,200 14%
Gross oil and gas revenue $ 332,643 371,824 (11%)
Net oil and gas revenue $ 200,862 247,853 (19%)
Partnership distributions $ 208,798 224,640 (7%)
Limited partner distributions $ 185,830 199,930 (7%)
Per unit distribution to limited partners $ 132.08 142.10 (7%)
Number of limited partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues decreased to $332,643 from $371,824
for the years ended December 31, 2001 and 2000, respectively, a decrease of
11%. 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 15%, or $4.48 per barrel, resulting in
a decrease of approximately $42,400 in revenues. Oil sales represented
72% of total oil and gas sales during the year ended December 31, 2001
as compared to 78% 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 3%, or $.10 per mcf, resulting in
an increase of approximately $2,300 in revenues.
The net total decrease in revenues due to the change in prices received
from oil and gas production is approximately $40,100. 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 340 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 $10,100 in revenues.
Gas production increased approximately 2,800 mcf or 14% during the same
period, resulting in an increase of approximately $11,100 in revenues.
The net total increase in revenues due to the change in production is
approximately $1,000.
Costs and Expenses
Total costs and expenses increased to $172,299 from $154,913 for the years
ended December 31, 2001 and 2000, respectively, an increase of 11%. The
increase is the result of higher lease operating costs, depletion expense
and general and administrative expense.
1. Lease operating costs and production taxes were 6% higher, or
approximately $7,800 more 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 $24,000 for the year ended December 31,
2001 from $15,000 for the same period in 2000. This represents an
increase of 60%. 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 the price of oil and gas used
to determine the Partnership's reserves for January 1, 2002 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 $6,000 as of
December 31, 2000.
Results of Operations
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 Percentage
December 31, Increase
2000 1999 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 29.73 17.74 68%
Average price per mcf of gas $ 3.98 2.35 69%
Oil production in barrels 9,800 10,770 (9%)
Gas production in mcf 20,200 24,940 (19%)
Gross oil and gas revenue $ 371,824 249,636 49%
Net oil and gas revenue $ 247,853 146,852 69%
Partnership distributions $ 224,640 85,000 164%
Limited partner distributions $ 199,930 75,650 164%
Per unit distribution to limited partners $ 142.10 53.77 164%
Number of limited partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues increased to $371,824 from $249,636
for the years ended December 31, 2000 and 1999, respectively, an increase
of 49%. 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 68%, or $11.99 per barrel, resulting in
an increase of approximately $117,500 in revenues. Oil sales
represented 78% of total oil and gas sales during the year ended
December 31, 2000 as compared to 77% 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 69%, or $1.63 per mcf, resulting in
an increase of approximately $32,900 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $150,400. 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 970 barrels or 9% during the
year ended December 31, 2000 as compared to the year ended December 31,
1999, resulting in a decrease of approximately $17,200 in revenues.
Gas production decreased approximately 4,470 mcf or 19% during the same
period, resulting in a decrease of approximately $11,100 in revenues.
The total decrease in revenues due to the change in production is
approximately $28,300.
Costs and Expenses
Total costs and expenses increased to $154,913 from $137,198 for the years
ended December 31, 2000 and 1999, respectively, an increase of 13%. The
increase is the result of higher lease operating costs, partially offset by
a decrease in depletion expense and general and administrative expense.
2. Lease operating costs and production taxes were 21% higher, or
approximately $21,200 more during the year ended December 31, 2000 as
compared to the year ended December 31, 1999. The increase in lease
operating costs and production taxes is due in part to an increase in major
repairs and maintenance, such as overhead and electrical repairs on two
leases, and in part to the rise in production taxes directly associated
with the rise in oil and gas prices received during the past year. The
rise in oil and gas prices for 2000 has allowed the Partnership to perform
these repairs and maintenance in the hopes of increasing production,
thereby increasing revenues.
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 8%
or approximately $1,500 during the year ended December 31, 2000 as
compared to the year ended December 31, 1999.
3. Depletion expense decreased to $15,000 for the year ended December 31,
2000 from $17,000 for the same period in 1999. This represents a
decrease of 12%. 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 decrease in depletion expense between the
comparative periods was the increase in the price of oil and gas used
to determine the Partnership's reserves for January 1, 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 $3,000 as of December 31, 1999.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2001, 2000 and 1999
was $160,893, $217,640 and $112,767, respectively. Excluding the effects
of depreciation, depletion and amortization, net income for the years ended
December 31, 2001, 2000 and 1999, would have been $184,893, $232,640 and
$129,767, respectively. Correspondingly, Partnership distributions for the
years ended December 31, 2001, 2000 and 1999 were $208,798, $224,640 and
$85,000, respectively. These differences are indicative of the changes in
oil and gas prices, production and property during 2001, 2000 and 1999.
The sources for the 2001 distributions of $208,798 were oil and gas
operations of approximately $197,000 and the change in oil and gas
properties of approximately $1,400, with the balance from available cash on
hand at the beginning of the period. The sources for the 2000
distributions of $224,640 were oil and gas operations of approximately
$228,800 and the change in oil and gas properties of approximately $(75),
resulting in excess cash for contingencies or subsequent distributions.
The sources for the 1999 distributions of $85,000 were oil and gas
operations of approximately $100,300 and the change in oil and gas
properties of approximately $(20), resulting in excess cash for
contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2001 were $208,798
of which $185,830 was distributed to the investor partners and $22,968 to
the Managing General Partners. The per unit distribution to investor
partners during the same period was $132.08. Total distributions during
the year ended December 31, 2000 were $224,640 of which $199,930 was
distributed to the investor partners and $24,710 to the Managing General
Partners. The per unit distribution to investor partners during the same
period was $142.10. 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 Partners. The per unit distribution to
investor partners during the same period was $53.77.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,586,353 have been made to the partners. As of December 31, 2001,
$1,412,230 or $1,003.72 per investor partner unit, has been distributed to
the investor partners, representing a 100% 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 $197,000 in
2001 compared to $228,800 in 2000 and approximately $100,300 in 1999. The
primary source of the 2001 cash flow from operating activities was
profitable operations.
Cash flows provided by (used in) investing activities were approximately
$1,400 in 2001 compared to $(75) in 2000 and approximately $(20) in 1999.
The principal source of the 2001 cash flow from investing activities was
the sale of equipment.
Cash flows used in financing activities were approximately $208,700 in 2001
compared to $224,600 in 2000 and approximately $85,100 in 1999. The only
use in the 2001 financing activities was the distributions to partners.
As of December 31, 2001, the Partnership had $45,400 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 19
Balance Sheets 20
Statement 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 92-A
(A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Developmental
Drilling Fund 92-A (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 92-A 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 92-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2001 and 2000
2001 2000
---- ----
Assets
------
Current assets:
Cash and cash equivalents $ 16,508 26,865
Receivable from Managing General Partner 28,977 41,053
- --------- ---------
Total current assets
45,485 67,918
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 1,313,124 1,314,517
Less accumulated depreciation,
depletion and amortization
1,127,240 1,103,240
- --------- ---------
Net oil and gas properties
185,884 211,277
- --------- ---------
$
231,369 279,195
========= =========
Liabilities and Partners' Equity
--------------------------------
Current liability - distribution payable $ 79 -
- --------- ---------
Partners' equity:
Managing General Partner 27,924 30,554
Investor partners 203,366 248,641
- --------- ---------
Total partners' equity
231,290 279,195
- --------- ---------
$
231,369 279,195
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-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 $ 332,643 371,824 249,636
Interest income from operations 549 729 329
-------
- ------- -------
333,192
372,553 249,965
-------
- ------- -------
Expenses
--------
Production 131,781 123,971 102,784
General and administrative 16,518 15,942 17,414
Depreciation, depletion and amortization 24,000 15,000 17,000
-------
- ------- -------
172,299
154,913 137,198
-------
- ------- -------
Net income $ 160,893 217,640 112,767
=======
======= =======
Net income allocated to:
Managing General Partner $ 20,338 25,590 14,274
=======
======= =======
Investor partners $ 140,555 192,050 98,493
=======
======= =======
Per investor partner unit $ 99.90 136.50 70.00
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
Years ended December 31, 2001, 2000 and 1999
Managing
General Investor
Partner Partners Total
-------- -------- -----
Balance at December 31, 1998 $ 24,750 233,678 258,428
Net income 14,274 98,493 112,767
Distributions (9,350) (75,650) (85,000)
------
- --------- --------
Balance at December 31, 1999 29,674 256,521 286,195
Net income 25,590 192,050 217,640
Distributions (24,710) (199,930)(224,640)
------
- --------- --------
Balance at December 31, 2000 30,554 248,641 279,195
Net income 20,338 140,555 160,893
Distributions (22,968) (185,830)(208,798)
------
- --------- --------
Balance at December 31, 2001 $ 27,924 203,366 231,290
======
========= ========
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 353,274 361,584 223,480
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(156,854) (133,476)(123,478)
Interest received 549 729 329
-------
- ------- -------
Net cash provided by operating activities 196,969 228,837
100,331
-------
- ------- -------
Cash flows from investing activities:
Addition to oil and gas properties - (75) (20)
Sale of equipment 1,393 - -
-------
- ------- -------
Net cash provided by (used in) investing activities1,393 (75) (20)
-------
- ------- -------
Cash flows used in financing activities:
Distributions to partners (208,719) (224,640) (85,080)
-------
- ------- -------
Net (decrease) increase in cash and cash
equivalents (10,357) 4,122 15,231
Beginning of period 26,865 22,743 7,512
-------
- ------- -------
End of period $ 16,508 26,865 22,743
=======
======= =======
(continued)
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-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 $ 160,893 217,640 112,767
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 24,000 15,000
17,000
Decrease (increase) in receivables 20,631 (10,240) (26,156)
(Decrease) increase in payables (8,555) 6,437 (3,280)
-------
- ------- -------
Net cash provided by operating activities $ 196,969 228,837 100,331
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 92-A, L.P. was organized under
the laws of the state of Delaware on May 5, 1992, for the purpose of
engaging primarily in the business of drilling developmental and
exploratory wells, to produce and market crude oil and natural gas
produced from such properties, and acquire leases which contain
drilling prospects. The activities of the Partnership should continue
for a term of 50 years, unless terminated at an earlier date as
provided for in the Partnership Agreement. The Partnership
anticipates selling 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 92-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 future gross 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 over or
under deliveries of gas. Under this method, the Partnership records
revenues based on the payments it has received for sales from
purchasers. As of December 31, 2001, 2000 and 1999, the Partnership
was not over or under produced.
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 assets at December 31,
2001 and 2000 was $173,234 and $194,608, respectively, less than that
shown on the accompanying Balance Sheets in accordance with generally
accepted accounting principles.
Southwest Developmental Drilling Fund 92-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.
Investor Partner Units
As of December 31, 2001, 2000 and 1999, there were 1,407 investor
units outstanding held by 105, 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 92-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
Nations Bank, 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, 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.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As provided for in the operating agreement
for each respective oil and gas property in which the Partnership has
an interest, the operator is paid an amount for administrative
overhead attributable to operating such properties, with such amounts
to Southwest Royalties, Inc. as operator approximating $23,600,
$22,700 and $22,400 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
$500, $3,700 and $2,900 for the years ended December 31, 2001, 2000
and 1999, respectively.
Southwest Royalties, Inc., the Managing General Partner, was paid an
administrative fee of $12,000 during 2001, 2000 and 1999 for
reimbursement of indirect general and administrative overhead
expenses.
In addition, a director and officer of the Managing General Partner is
a partner in a law firm, with such firm providing legal services to
the Partnership. There were no legal services for December 31, 2001,
2000 and 1999.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $29,000 and $41,100 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2001 and 2000, respectively.
Southwest Developmental Drilling Fund 92-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 purchaser, where the loss of one would
have a material adverse impact on the Partnership. Three purchasers
accounted for 93% of the Partnership's total oil and gas production
during 2001: Plains Marketing LP for 58%, Duke Energy Field Services
for 21% and Navajo Refining Company, Inc. for 14%. Three purchasers
accounted for 94% of the Partnership's total oil and gas production
during 2000: Plains Marketing LP for 63%, Navajo Refining Company,
Inc. for 16% and Duke Energy Transport and Trad. for 15%. Three
purchasers accounted for 95% of the Partnership's total oil and gas
production during 1999: Scurlock Permian LLC for 59%, Duke Energy
Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%.
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 76,000 168,000
Production (11,000) (25,000)
Revisions of estimates in place 44,000 166,000
------- -------
December 31, 1999 109,000 309,000
Production (10,000) (20,000)
Revisions of estimates in place 11,000 (47,000)
------- -------
December 31, 2000 110,000 242,000
Revisions of estimates in place (22,000) 26,000
Production (9,000) (23,000)
------- -------
December 31, 2001 79,000 245,000
======= =======
Proved developed reserves -
December 31, 1999 109,000 309,000
======= =======
December 31, 2000 110,000 242,000
======= =======
December 31, 2001 79,000 245,000
======= =======
All of the Partnership's reserves are located within the continental
United States.
Southwest Developmental Drilling Fund 92-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
*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
$18.90 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 $2.34 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. 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. All of the proved reserves are included in the engineering
reports which evaluate the Partnership's present reserves.
Southwest Developmental Drilling Fund 92-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 $ 2,059,000 5,290,000 3,328,000
Production and development costs 1,334,000 2,403,000 1,838,000
--------- --------- ---------
Future net cash flows 725,000 2,887,000 1,490,000
10% annual discount for estimated
timing of cash flows 260,000 1,309,000 603,000
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 465,000 1,578,000 887,000
========= ========= =========
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 $ (201,000) (248,000) (147,000)
Changes in prices and production costs (1,178,000) 866,000
374,000
Changes of production rates
(timing) and others 177,000 (49,000) (3,000)
Revisions of previous
quantities estimates (69,000) 33,000 396,000
Accretion of discount 158,000 89,000 24,000
Discounted future net
cash flows -
Beginning of year 1,578,000 887,000 243,000
--------- --------- --------
End of year $ 465,000 1,578,000 887,000
========= ========= ========
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 92-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 $ 124,995 75,628 66,151 66,418
Total expenses 43,013 50,019 39,776 39,491
Net income 81,982 25,609 26,375 26,927
Net income per limited
partners unit 51.31 15.81 16.14 16.64
2000:
Total revenues $ 90,020 92,567 108,127 81,839
Total expenses 37,602 37,618 45,451 34,242
Net income 52,418 54,949 62,676 47,597
Net income per limited
partners unit 32.77 34.52 39.25 29.95
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 $12,000 during 2001, 2000 and 1999 as an administrative fee for
reimbursement of indirect general and administrative expenses.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no investor partners who own of record, or are known by the
Managing General Partner to beneficially own, more than five percent of the
Partnership's investor partner interests.
The Managing General Partner owns an 11 percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns 5.0 limited partner units, or .4% limited partner interest. The
Managing General Partner total percentage interest ownership in the
Partnership is 11.3%.
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.
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 .4%
Interest Managing General Partner 5.0 Units
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns .4%
Interest Chairman of the Board, 5.0 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 .4%
Interest Secretary and Director of 5.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
633 Chestnut Street
Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns .4%
Interest Vice President and CFO of 5.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns .4%
Interest Vice President, Marketing of 5.0 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns .4%
Interest Director, of Southwest 5.0 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 $12,000 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 $23,600 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 $500 for the period ended
December 31, 2001.
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 Sheet
Statement of Changes in Partners' Equity
Statement of Cash Flows
Notes to Financial Statements
(2) Schedules I through XIII are omitted
because they are not applicable, or because the required
information is shown in the financial statements or the
notes thereto.
(3) Exhibits:
Exhibit 4(a): Certificate of Limited
Partnership of Southwest Developmental
Drilling Fund 92-A, L.P., dated May 5,
1992 (Incorporated by reference from
Partnership's Form 10-K for the fiscal
year ended December 31, 1992).
Exhibit 4(b): Agreement of Limited
Partnership of Southwest Developmental
Drilling Fund 92-A, L.P. dated May 5, 1992
(Incorporated by reference from
Partnership's Form 10-K for the fiscal
year ended December 31, 1992).
Exhibit 4(c): First Amendment to
Amended and Restated Certificate of
Limited Partnership of Southwest
Developmental Drilling Fund 92-A. L.P.,
dated as of February 22, 1993
(Incorporated by reference from Partner
ship's Form 10-K for the fiscal year ended
December 31, 1993).
Exhibit 4(d): Second Amendment to
Amended and Restated Certificate of
Limited Partnership of Southwest
Developmental Drilling Fund 92-A. L.P.,
dated as of March 26, 1993 (Incorporated
by reference from Partnership's Form 10-K
for the fiscal year ended December 31,
1993).
Exhibit 4(e): Second Amended and
Restated Certificate of Limited
Partnership of Southwest Developmental
Drilling Fund 92-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
Reports on Form 8-K
(b) No report on Form 8-K was filed 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 92-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