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, 1997
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 33-47668-02
Southwest Royalties Institutional Income Fund XI-B, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2427289
(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 partnership 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 43. There is no
exhibit index.
Table of Contents
Item Page
Part I
1. Business 3
2. Properties 6
3. Legal Proceedings 9
4. Submission of Matters to a Vote of Security Holders 9
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 10
6. Selected Financial Data 11
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 12
8. Financial Statements and Supplementary Data 19
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 36
Part III
10. Directors and Executive Officers of the Registrant 37
11. Executive Compensation 40
12. Security Ownership of Certain Beneficial Owners and
Management 40
13. Certain Relationships and Related Transactions 41
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 42
Signatures 43
Part I
Item 1. Business
General
Southwest Royalties Institutional Income Fund XI-B, L.P. (the "Partnership"
or "Registrant") was organized as a Delaware limited partnership on August
31, 1993. The offering of limited partnership interests began October 25,
1993, as part of a shelf offering registered under the name Southwest
Royalties Institutional 1992-93 Income Program. Minimum capital
requirements for the Partnership were met on December 8, 1993 and concluded
August 20, 1994. The Partnership has no subsidiaries.
As of December 31, 1996, the Partnership had utilized approximately
$2,008,600 of limited partner capital contributions to acquire interests in
oil and gas properties. All excess capital, $89,489, and the associated
organization costs of $3,132, has been distributed to the limited partners
in proportion to their capital contributions as a return of capital.
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 130 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. H. H.
Wommack, III, a stockholder, director, President and Treasurer of the
Managing General Partner, is also a general partner. The Partnership has
no employees.
Principal Products, Marketing and Distribution
The Partnership has acquired and holds royalty interest and net profit
interests in oil and gas properties located in New Mexico and Texas. 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. With some periodic
exceptions, since the early 1980's, there has been a worldwide oversupply
of oil; therefore, market prices have declined significantly. 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 for
oil and natural gas.
1997 was another volatile year in the oil market. Prices ranged from a
high of approximately $26 in the first quarter to a low near $18 per
barrel. Two contributing factors that influence the oil industry are the
strength of the economy and activity in the Middle East. Both influenced
the supply and demand of oil, and both played roles in price swings this
year. Economic expansion throughout the world enabled consumption to
surpass 70 million barrels of oil per day. However, early in the year,
producing countries failed to make up the difference in supply, placing
upward pressure on prices. U.S. production fell slightly in 1997 to
average roughly 6.4 million barrels of oil per day. Over the Thanksgiving
weekend, OPEC agreed to increase their crude oil production ceiling by
approximately 10%, but experts have said that many OPEC countries were
already producing beyond their quotas, therefore, capacity is not expected
to expand severely. Then on December 4th, the UN Security Council approved
a renewal of the Iraqi oil-for-food program. The OPEC agreement and the
UN's decision on the oil-for-food program will certainly increase the world
supply of oil and most likely depress prices in the near term. However,
world demand is expected to continue with strong growth in 1998.
The December 31, 1997 NYMEX oil price of $17.64 dropped to $14.32 as of
March 18, 1998. The price decline in the first quarter of 1998 could cause
a material write down in oil and gas properties and a possible reduction in
future distributions to investors.
Overall the 1997 average price of natural gas increased nationwide from the
1996 rates. In some areas the increase was as high as 15%. The 1996 and
1997 average prices are by far the highest realized by the industry since
1985. The 1998 average price is expected to remain above the $2.00 per
MMBTU level, however some early signs indicate that the prices will be
softer in 1998 than they were in 1997. Forecasts for a mild winter and the
lack of gas storage withdrawals are fueling speculation that the U.S. has
an excess supply of gas thus driving the prices down to the early 1996
levels.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
1997 48% 52%
1996 53% 47%
1995 54% 46%
As the table indicates, the Partnership's revenue is almost evenly divided
between its oil and gas production, the Partnership revenues will be highly
dependent upon the future prices and demands for oil and gas.
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 volume sold by the Partnership are not expected to fluctuate
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
71% of the Partnership's total oil and gas production during 1997: Navajo
Refining Company, Inc. 36%, and American Processing 35%. Two purchasers
accounted for 69% of the Partnership's total oil and gas production during
1996: Navajo Refining Company, Inc. 41%, and American Processing 28%.
Two purchasers accounted for 69% of the Partnership's total oil and gas
production during 1995: Navajo Refining Company, Inc. and American
Processing purchased 40% and 29%, respectively. All purchasers of the
Partnership's oil and gas production are unrelated third parties. In the
event any of these purchasers 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 sales of 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, 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 will be 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 will be 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,
1997 there were 130 individuals directly employed by the Managing General
Partner in various capacities.
Item 2. Properties
In determining whether an interest in a particular producing property was
to be acquired, the Managing General Partner considered such criteria as
estimated oil and gas reserves, 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, 1997, the Partnership possessed an interest in oil and
gas properties located in Eddy and Lea Counties of New Mexico; Andrews,
Cochran, Dawson, Howard, Midland, Reagan, Reeves, Schleicher, Stonewall,
Upton, Ward and Winkler Counties of Texas. These properties consist of
various interests in 103 wells and units.
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 1997 and 1996.
During 1995, the Partnership acquired the Kaiser State 44 acquisition,
located in Lea County, New Mexico, for approximately $90,000. The
acquisition was effective as of June 1, 1995 and was purchased from an
unrelated third party, Elkhorn Oil and Gas, LLC.
In compliance with the Partnership Agreement, if the Partnership should
purchase a producing property from the Managing General Partner, such
purchase price would be prior cost, adjusted for any intervening operation.
If such adjusted cost was greater than fair market value, of if specific
cost was unable to be determined, such purchase price would be fair market
value as determined by an independent reservoir engineer.
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)
- ----------------- ------------ ------ --------- ---------
Custer & Wright 11/94 at 39 23,740 613,428
Winkler County, 1% to 40%
Texas net profits
interests
Michael Dingman 9/94 at 59 31,166 118,644
Midland, Stonewall, .5% to 50%
Reeves, Reagan, net profits
Dawson, Schleicher, interests
Winkler, Ward,
Andrews, Cochran
Counties, Texas:
Eddy County,
New Mexico
*The reserve estimates were prepared as of January 1, 1998, by Donald R.
Creamer, P.E., an independent registered petroleum engineer. The reserve
estimates were made in accordance with guidelines established by the
Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-
X. Such guidelines require oil and gas reserve reports be prepared under
existing economic and operating conditions with no provisions for price and
cost escalation except by contractual arrangements.
The New York Mercantile Exchange price at December 31, 1997 of $17.64 was
used as the beginning basis for the oil price. Oil price adjustments from
$17.64 per barrel were made in the individual evaluations to reflect oil
quality, gathering and transportation costs. The results are an average
price received at the lease of $16.38 per barrel in the preparation of the
reserve report as of January 1, 1998.
In the determination of the gas price, the New York Mercantile Exchange
price at December 31, 1997 of $2.26 was used as the beginning basis. Gas
price adjustments from $2.26 per Mcf were made in the individual
evaluations to reflect BTU content, gathering and transportation costs and
gas processing and shrinkage. The results are an average price received at
the lease of $2.15 per Mcf in the preparation of the reserve report as of
January 1, 1998.
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 1997.
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 a proved developed
producing, proved developed non-producing and proved undeveloped. All of
the proved reserves are included in the engineering reports which evaluate
the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to farmout
arrangements with the Managing General Partner or unrelated third parties.
Generally, the Partnership retains a carried interest such as an overriding
royalty interest under the terms of a farmout, or receives cash.
The Partnership or the owners of properties in which the Partnership owns
an interest can engage in workover projects or supplementary recovery
projects, for example, to extract behind the pipe reserves which qualify as
proved developed non-producing reserves. See Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operation.
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 1997 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters
Market Information
Limited partnership interests, or units, in the Partnership are currently
being offered and sold for a price of $500. Limited 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
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 NationsBank, N.A. of
Midland, Texas plus one percent (1%), which value shall be further reduced
by a risk factor discount of no more than one-third (1/3) to be determined
by the Managing General Partner in its sole and absolute discretion. As of
December 31, 1997, 1996 and 1995, no limited partner units were purchased
by the Managing General Partner.
Number of Limited Partner Interest Holders
As of December 31, 1997, there were 176 holders of limited partner units in
the Partnership.
Distributions
Pursuant to Article III, Section 3.05 of the Partnership's Certificate and
Agreement of Limited Partnership, "Net Cash Flow" shall be distributed to
the partners on a monthly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's investments in producing oil and gas
properties, less (i) General and Administrative Costs, (ii) Direct Costs,
(iii) Operating Costs, and (iv) any reserves necessary to meet current and
anticipated needs of the Partnership, as determined in the sole discretion
of the Managing General Partner."
During 1997, twelve monthly distributions were made totaling $300,600, with
$270,540 distributed to the limited partners and $30,060 to the general
partners. For the year ended December 31, 1997, distributions of $55.77
per limited partner unit were made, based upon 4,851 limited partner units
outstanding. During 1996, twelve monthly distributions were made totaling
$338,739, with $314,239 distributed to the limited partners and $24,500 to
the general partners. For the year ended December 31, 1996, distributions
of $64.78 per limited partner unit were made, based upon 4,851 limited
partner units outstanding. During 1995, twelve monthly distributions were
made totaling $242,797, with $218,971 distributed to the limited partners
and $23,826 to the general partners. For the year ended December 31, 1995,
distributions of $45.14 per limited partner unit were made, based on 4,851
limited partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
1997, 1996, 1995, 1994 and the period from December 8, 1993, date of
inception, through December 31, 1993, should be read in conjunction with
the financial statements included in Item 8:
Period from
inception
Years ended through
December 31, December 31,
--------------------------------------------------
- --
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
Revenues $ 304,410 395,095 251,501 150,925 1,287
Net income (loss) (467,687) 180,841 (99,700) 87,328 1,287
Partners' share of
net income (loss):
General partners 25,491 34,555 19,946 10,522 -
Limited partners (493,178) 146,286 (119,646) 76,806 1,287
Limited partners' net
income (loss) per unit (101.67) 30.16 (24.66) 15.83
.50
Limited partner's cash
distribution per unit 55.77 64.78 45.14 9.89
- -
Total assets $ 909,626 1,677,907 1,835,8342,184,9551,132,972
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized as a
Delaware limited partnership on August 31, 1993. The offering of limited
partnership interests began October 25, 1993, as part of a shelf offering
registered under the name Southwest Royalties Institutional 1992-93 Income
Program. Minimum capital requirements for the Partnership were met on
December 8, 1993, and the Offering Period terminated August 20, 1994 with
174 limited partners purchasing 4,851 units for $2,425,500.
The Partnership was formed to acquire non-operating interests in producing
oil and gas properties, to produce and market crude oil and natural gas
produced from such properties and to distribute any net proceeds from
operations to the general and limited partners. Net revenues from
producing oil and gas properties will not be reinvested in other revenue
producing assets except to the extent that producing facilities and wells
are reworked or where methods are employed to improve or enable more
efficient recovery of oil and gas reserves. The economic life of the
Partnership will thus depend on the period over which the Partnership's oil
and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore,
distributions to partners will depend primarily on changes in the prices
received for production, changes in volumes of production sold, lease
operating expenses, enhanced recovery projects, offset drilling activities
pursuant to farmout arrangements and on the depletion wells. Since wells
deplete over time, production can generally be expected to decline from
year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the limited
partners has fluctuated over the past few years and is expected to
fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing workovers
during the next few years to enhance production. The Partnership could
possibly experience a lower than normal decline during that time and
thereafter, could possibly experience a normal decline.
Results of Operations
A. General Comparison of the Years Ended December 31, 1997 and 1996
The following table provides certain information regarding performance
factors for the years ended December 31, 1997 and 1996:
Year Ended Percentage
December 31, Increase
1997 1996 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 19.37 20.65 (6%)
Average price per mcf of gas $ 2.22 2.15 3%
Oil production in barrels 11,400 15,400 (26%)
Gas production in mcf 109,000 133,300 (18%)
Income from net profits interests $ 206,956 315,055 (34%)
Partnership distributions $ 300,600 338,739 (11%)
Limited partner distributions $ 270,540 314,239 (14%)
Per unit distribution to limited partners $ 55.77 64.78 (14%)
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests decreased to $206,956
from $315,055 for the years ended December 31, 1997 and 1996, respectively,
a decrease of 34%. The principal factors affecting the comparison of the
years ended December 31, 1997 and 1996 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the year ended December 31, 1997 as compared to the
year ended December 31, 1996 by 6%, or $1.28 per barrel, resulting in a
decrease of approximately $19,700 in income from net profits interests.
Oil sales represented 48% of total oil and gas sales during the year
ended December 31, 1997 as compared to 53% during the year ended
December 31, 1996.
The average price for an mcf of gas received by the Partnership
increased during the same period by 3%, or $.07 per mcf, resulting in
an increase of approximately $9,300 in income from net profits
interests.
The net total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$10,400 . 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 4,000 barrels or 26% during the
year ended December 31, 1997 as compared to the year ended December 31,
1996, resulting in a decrease of approximately $77,500 in income from
net profits interests.
Gas production decreased approximately 24,300 mcf or 18% during the
same period, resulting in a decrease of approximately $53,900 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $131,400. The decrease in
production is primarily attributable to downtime experienced on two
wells, one well being shut-in and normal decline.
3. Lease operating costs and production taxes were 12% lower, or
approximately $33,300 less during the year ended December 31, 1997 as
compared to the year ended December 31, 1996. Decrease is due
primarily to pulling expense incurred on one well in 1996 and post
closing costs recorded in 1996 on the purchase of the Kaiser State #44.
4. As of December 31, 1997, miscellaneous income was approximately
$94,424. The income is a result of a purchase agreement, on the Tar
Baby lease, that guarantees the Partnership a net income of
approximately $3,400 each month from October 1994 to January 1998.
Costs and Expenses
Total costs and expenses increased to $772,097 from $214,254 for the years
ended December 31, 1997 and 1996, respectively, an increase of 260%. The
increase is the result of higher depletion expense and a provision for
impairment of oil and gas properties.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 2%
or approximately $800 during the year ended December 31, 1997 as
compared to the year ended December 31, 1996.
2. Depletion expense increased to $226,000 for the year ended December
31, 1997 from $158,000 for the same period in 1996. This represents an
increase of 43%. Depletion is calculated using the units of revenue method
of amortization based on a percentage of current period gross revenues to
total future gross oil and gas revenues, as estimated by the Partnership's
independent petroleum consultants.
A contributing factor to the 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, 1998 as compared
to 1997. Another contributing factor was due to the impact of
revisions of previous estimates on reserves. Revisions of previous
estimates can be attributed to the changes in production performance,
oil and gas price and production costs. The impact of the revision
would have increased depletion expense approximately $98,000 as of
December 31, 1996.
The Partnership reduced the net capitalized costs of oil and gas
properties in 1997 by approximately $489,154. The write-down has the
effect of reducing net income, but did not affect cash flow or partner
distributions.
Results of Operations
B. General Review of the Years Ended December 31, 1996 and 1995
The following table provides certain information regarding performance
factors for the years ended December 31, 1996 and 1995.
Year Ended Percentage
December 31, Increase
1996 1995 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 20.65 17.10 21%
Average price per mcf of gas $ 2.15 1.56 38%
Oil production in barrels 15,400 17,500 (12%)
Gas production in mcf 133,300 160,000 (17%)
Income from net profits interests $ 315,055 246,752 28%
Partnership distributions $ 338,739 242,797 40%
Limited partner distributions $ 314,239 218,971 44%
Per unit distribution to limited
partners $ 64.78 45.14 44%
Number of limited partner units 4,851 4,851
Revenues
The Partnership's income from net profits interests increased to $315,055
from $246,752 for the years ended December 31, 1996 and 1995, respectively,
an increase of 28%. The principal factors affecting the comparison of the
years ended December 31, 1996 and 1995 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the year ended December 31, 1996 as compared to the
year ended December 31, 1995 by 21%, or $3.55 per barrel, resulting in
an increase of approximately $62,100 in income from net profits
interests. Oil sales represented 53% of total oil and gas sales during
the year ended December 31, 1996 as compared to 54% during the year
ended December 31, 1995.
The average price for an mcf of gas received by the Partnership
increased during the same period by 38%, or $.59 per mcf, resulting in
an increase of approximately $94,400 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$156,500. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 2,100 barrels or 12% during the
year ended December 31, 1996 as compared to the year ended December 31,
1995, resulting in a decrease of approximately $43,400 in income from
net profits interests.
Gas production decreased approximately 26,700 mcf or 17% during the
same period, resulting in a decrease of approximately $57,400 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $100,800. The decrease is
primarily a result of surface problems.
3. As of December 31, 1996, miscellaneous income was approximately
$77,700. The income is a result of a purchase agreement, on the Tar
Baby lease, that guarantees the Partnership a net income of
approximately $3,400 each month from October 1994 to January 1998.
4. Lease operating costs and production taxes were 3% lower, or
approximately $9,700 less during the year ended December 31, 1996 as
compared to the year ended December 31, 1995.
Costs and Expenses
Total costs and expenses decreased to $214,254 from $351,201 for the years
ended December 31, 1996 and 1995, respectively, a decrease of 39%. The
decrease is the result of lower depletion expense, offset by an increase in
general and administrative expense.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 2%
or approximately $800 during the year ended December 31, 1996 as
compared to the year ended December 31, 1995.
2. Depletion expense decreased to $158,000 for the year ended December 31,
1996 from $211,000 for the same period in 1995. This represents a
decrease of 25%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants.
A contributing factor to the decline in depletion expense between the
comparative periods was the increase in the price of oil and gas used
to determine the Partnership's reserves for January 1, 1997 as compared
to 1996. Another contributing factor was due to the impact of
revisions of previous estimates on reserves. Revisions of previous
estimates can be attributed to the changes in production performance,
oil and gas price and production costs. The impact of the revision
would have decreased depletion expense approximately $15,000 as of
December 31, 1995.
C. Revenue and Distribution Comparison
Partnership income or (loss) for the years ended December 31, 1997, 1996
and 1995 was $(467,687), $180,841 and $(99,700), respectively. Excluding
the effects of depreciation, depletion, amortization and provision for
impairment, net income would have been $254,907 in 1997, $346,439 in 1996
and $203,652 in 1995. Correspondingly, Partnership distributions for the
years ended December 31, 1997, 1996 and 1995 were $300,600, $338,739 and
$242,797, respectively. These differences are indicative of the changes in
oil and gas prices, production and property.
The source for the 1997 distributions of $300,600 were oil and gas
operations of approximately $285,200, with the balance from available cash
on hand at the beginning of the period. The sources for the 1996
distributions of $338,739 were oil and gas operations of approximately
$259,900, the refund of organization cost of approximately $3,100 and
excess capital of approximately $89,500, resulting in excess cash for
contingencies or subsequent distributions. The sources for the 1995
distributions of $242,797, were oil and gas operations of $235,275, reduced
by additions to oil and gas properties of $113,583, with the balance from
available cash on hand at beginning of period.
Total distributions during the year ended December 31, 1997 were $300,600
of which $270,540 was distributed to the limited partners and $30,060 to
the general partners. The per unit distribution to limited partners during
the same period was $55.77. Total distributions during the year ended
December 31, 1996 were $338,739 of which $314,239 was distributed to the
limited partners and $24,500 to the general partners. The per unit
distribution to limited partners during the same period was $64.78. Total
distributions during the year ended December 31, 1995 were $242,797 of
which $218,971 was distributed to the limited partners and $23,826 to the
general partners. The per unit distribution to limited partners during the
same period was $45.14.
Since inception of the Partnership, cumulative monthly cash contributions
of $930,939 have been made to the partners. As of December 31,1997
$851,703 or $175.57 per limited partner unit, has been distributed to the
limited partners, representing a 35% return of the capital contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
net profits interests in oil and gas properties. The Partnership knows of
no material change, nor does it anticipate any such change.
The December 31, 1997 NYMEX oil price of $17.64 dropped to $14.32 as of
March 18, 1998. The price decline in the first quarter of 1998 could cause
a material write down in oil and gas properties and a possible reduction in
future distributions to investors.
Cash flows provided by operating activities were approximately $285,200 in
1997 compared to $259,900 in 1996 and approximately $235,000 in 1995. The
primary source of the 1997 cash flow from operating activities was
profitable operations.
The Partnership had no cash flows from investing activities in 1997. Cash
flows from investing activities were approximately $3,100 in 1996 compared
to $(113,500) in 1995.
Cash flows used in financing activities were approximately $300,500 in 1997
compared to $338,800 in 1996 and approximately $243,000 in 1995. The only
1997 use in financing activities was the distribution to partners.
As of December 31, 1997, the Partnership had approximately $111,300 in
working capital. The Managing General Partner knows of no other
commitments and believes the revenues generated from operations will be
adequate to meet the operating needs of the Partnership.
Information Systems for the Year 2000
The Managing General Partner provides all data processing needs of the
Partnership. The Managing General Partner has reviewed and evaluated its
information systems to determine if its systems accurately process data
referencing the year 2000. Primarily all necessary programming
modifications to correct year 2000 referencing in the Managing General
Partners internal accounting and operating systems have been made to-date.
However the Managing General Partner has not completed its evaluation of
its vendors and suppliers systems to determine the effect, if any, the non-
compliance of such systems would have on the operation of the Managing
General Partnership or the operations of the Partnership.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Independent Auditors Reports 20
Balance Sheets 22
Statements of Operations 23
Statements of Changes in Partners' Equity 24
Statements of Cash Flows 25
Notes to Financial Statements 27
INDEPENDENT AUDITORS REPORT
The Partners
Southwest Royalties Institutional
Income Fund XI-B, L.P.
(A Delaware Limited Partnership):
We have audited the accompanying balance sheet of Southwest Royalties
Institutional Income Fund XI-B, L.P. (the "Partnership") as of December 31,
1997, and the related statement of operations, changes in partners' equity
and cash flows for the year then ended. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the 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 audit
provides 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 Royalties
Institutional Income Fund XI-B, L.P. as of December 31, 1997 and the
results of its operations and its cash flows for the year then ended in
conformity with generally accepted accounting principles.
KPMG Peat Marwick LLP
Midland, Texas
March 18, 1998
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners
Southwest Royalties Institutional
Income Fund XI-B, L.P.
Midland, Texas
We have audited the accompanying balance sheet of Southwest Royalties
Institutional Income Fund XI-B, L.P. as of December 31, 1996 and the
related statements of operations, changes in partners' equity and cash
flows for the years ended December 31, 1996 and 1995. These financial
statements are the responsibility of the partnership's management. Our
responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Royalties
Institutional Income Fund XI-B, L.P. as of December 31, 1996 and the
results of its operations and its cash flows for the years ended December
31, 1996 and 1995, in conformity with generally accepted accounting
principles.
JOSEPH DECOSIMO AND COMPANY
A Tennessee Registered Limited Liability
Partnership
Chattanooga, Tennessee
March 14, 1997
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 1997 and 1996
1997 1996
---- ----
Assets
Current assets:
Cash and cash equivalents $ 4,948 20,225
Receivable from Managing General Partner 54,454 79,012
Other receivable 51,887 57,669
Distribution receivable - 70
- --------- ---------
Total current assets
111,289 156,976
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 2,008,569 2,008,569
Less accumulated depreciation,
depletion and amortization
1,217,154 502,000
- --------- ---------
Net oil and gas properties
791,415 1,506,569
- --------- ---------
Organization costs, net of amortization
of $30,380 in 1997 and $22,940 in 1996 6,922 14,362
- --------- ---------
$
909,626 1,677,907
========= =========
Liabilities and Partners' Equity
Current liability - Distribution payable $ 6 -
- --------- ---------
Partners' equity:
General partners 11,278 15,847
Limited partners 898,342 1,662,060
- --------- ---------
Total partners' equity
909,620 1,677,907
- --------- ---------
$
909,626 1,677,907
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Operations
Years ended December 31, 1997, 1996 and 1995
1997 1996 1995
---- ---- ----
Revenues
Income from net profits interests $ 206,956 315,055 246,752
Interest income from capital contributions - 895
4,201
Interest from operations 3,030 1,476 548
Miscellaneous income 94,424 77,669 -
-------
- ------- -------
304,410
395,095 251,501
-------
- ------- -------
Expenses
General and administrative 49,503 48,656 47,849
Depreciation, depletion and amortization 233,440 165,598 219,352
Provision for impairment of oil and gas
properties 489,154 - 84,000
-------
- ------- -------
772,097
214,254 351,201
-------
- ------- -------
Net income (loss) $ (467,687) 180,841 (99,700)
=======
======= =======
Net income (loss)allocated to:
Managing General Partner $ 22,942 31,099 17,951
=======
======= =======
General Partner $ 2,549 3,456 1,995
=======
======= =======
Limited partners $ (493,178) 146,286(119,646)
=======
======= =======
Per limited partner unit $ (101.67) 30.16 (24.66)
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Changes in Partners' Equity
Years ended December 31, 1997, 1996 and 1995
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, 1994 $ 9,672 2,168,6302,178,302
Net income (loss) 19,946 (119,646) (99,700)
Distributions (23,826) (218,971)(242,797)
-------
- --------- ---------
Balance at December 31, 1995 5,792 1,830,0131,835,805
Net income 34,555 146,286 180,841
Distributions (24,500) (314,239)(338,739)
-------
- --------- ---------
Balance at December 31, 1996 15,847 1,662,0601,677,907
Net income (loss) 25,491 (493,178)(467,687)
Distributions (30,060) (270,540)(300,600)
-------
- --------- ---------
Balance at December 31, 1997 $ 11,278 898,342 909,620
=======
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 1997, 1996 and 1995
1997 1996 1995
---- ---- ----
Cash flows from operating activities:
Cash received from net profits interests $ 331,720 306,153 278,371
Cash paid to Managing General Partner
for administrative fees and general
and administrative overhead
(49,503) (48,656)(47,982)
Interest received 3,030 2,371 4,886
--------
- -------- ----------
Net cash provided by operating activities 285,247 259,868
235,275
--------
- -------- ----------
Cash flows from investing activities:
Organization costs - 3,132 -
Additions to oil and gas properties - -(113,583)
--------
- -------- ----------
Net cash provided by (used in) investing
activities - 3,132
(113,583)
--------
- -------- ----------
Cash flows from financing activities:
Distributions to partners (300,524) (338,838)(242,740)
--------
- -------- ----------
Net decrease in cash and cash equivalents (15,277) (75,838)(121,048)
Beginning of period 20,225 96,063 217,111
--------
- -------- ----------
End of period $ 4,948 20,225 96,063
========
======== ==========
(continued)
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows, continued
Years ended December 31, 1997, 1996 and 1995
1997 1996 1995
---- ---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities:
Net income (loss) $ (467,687) 180,841 (99,700)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 233,440 165,598
219,352
(Increase) decrease in receivables 30,339 (86,571) 31,756
Increase (decrease) in payables - - (133)
Provision for impairment of oil and gas
properties 489,154 -
84,000
-------
- ------- -------
Net cash provided by operating activities $ 285,247 259,868 235,275
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-B, L.P. was organized
under the laws of the state of Delaware on August 31, 1993, for the
purpose of acquiring producing oil and gas properties 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 will sell 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 and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partner Partners (1)
------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital
contributions 100% -
Oil and gas revenues 90% 10%
All other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to the Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. Gain or loss on
the sale of oil and gas properties is not recognized unless
significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization
of oil and gas properties is computed under the units of revenue
method. Under the units of revenue method, depreciation, depletion
and amortization is computed on the basis of current gross revenues
from production in relation to future gross revenues, based on current
prices, from estimated production of proved oil and gas reserves.
Under the units of revenue method, the Partnership computes the
provision by multiplying the total unamortized cost of oil and gas
properties by an overall rate determined by dividing (a) oil and gas
revenues during the period by (b) the total future gross oil and gas
revenues as estimated by the Partnership's independent petroleum
consultants. It is reasonably possible that those estimates of
anticipated future gross revenues, the remaining estimated economic
life of the product, or both could be changed significantly in the
near term due to the potential fluctuation of oil and gas prices or
production. The depletion estimate would also be affected by this
change.
Should the net capitalized costs exceed the estimated present value of
oil and gas reserves, discounted at 10%, such excess costs would be
charged to current expense. The Partnership reduced the net
capitalized costs of oil and gas properties in 1997 by approximately
$489,000. This write-down has the effect of reducing net income, but
did not affect cash flow or partnership distributions. As of December
31, 1996, the net capitalized costs did not exceed the estimated value
of oil and gas reserves. The Partnership reduced the net capitalized
costs of oil and gas properties in 1995 by approximately $84,000.
This write-down has the effect of reducing net income, but did not
affect cash flow or partner distributions.
The Partnership's interest in oil and gas properties consists of net
profits interests in proved properties located within the continental
United States. A net profits interest is created when the owner of a
working interest in a property enters into an arrangement providing
that the net profits interest owner will receive a stated percentage
of the net profit from the property. The net profits interest owner
will not otherwise participate in additional costs and expenses of the
property.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Estimates and Uncertainties
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
Organization Costs
Organization costs are stated at cost and are amortized over sixty
months using the straight-line method.
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, 1997, 1996 and
1995, 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 oil and gas properties at December 31,
1997 and 1996 is $306,929 more and $100,499 less than that shown on
the accompanying Balance Sheet in accordance with generally accepted
accounting principles.
Southwest Royalties Institutional Income Fund XI-B, 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 Limited Partner Units
As of December 31, 1997, 1996 and 1995 there were 4,851 limited
partner units outstanding held by 176 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.
Recent Accounting Pronouncements
In June 1997, the FASB issued "Reporting Comprehensive Income," SFAS
No. 130, which establishes standards for reporting and display of
comprehensive income and its components in a full set of general-
purpose financial statements. Specifically, this statements requires
that an enterprise (i) classify items of other comprehensive income by
their nature in a financial statement and (ii) display the accumulated
balance of other comprehensive income separately from retained
earnings and additional paid-in capital in the equity section of a
statement of financial position. This statement is effective for
fiscal years beginning after December 15, 1997. The Partnership
anticipates adoption of SFAS No. 130 in its year ended December 31,
1998 financial statements.
Comprehensive income consists of the change in equity of a business
enterprise during a period from transactions and other events and
circumstances from nonowner sources. Specifically, this includes net
income and other comprehensive income, which is made up of certain
changes in assets and liabilities that are not reported in a statement
of operations but are included in the balances within a separate
component of equity in a statement of financial position. Such
changes include, but are not limited to, unrealized gains for
marketable securities and futures contracts, foreign currency
translation adjustments and minimum pension liability adjustments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Oil and Gas Properties
Costs incurred in connection with the Partnership's oil and gas
producing activities for the year ended December 31, 1997, 1996 and
1995 are as follows:
1997 1996 1995
---- ---- ----
Acquisition costs $ - - 90,000
======= ======= =========
Developmental costs $ - - 17,063
======= ======= =========
All of the Partnership's properties were proved when acquired.
4. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by
NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
shall be further reduced by a risk factor discount of no more than one-
third (1/3) to be determined by the Managing General Partner in its
sole and absolute discretion.
The Partnership is subject to various federal, state and local
environmental laws and regulations which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 1997, 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 Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As is usual in the industry and as provided
for in the operating agreement for each respective oil and gas
property in which the Partnership has an interest, the operator is
paid an amount for administrative overhead attributable to operating
such properties, with such amounts to Southwest Royalties, Inc. as
operator approximating $56,000, $57,200 and $55,000 for the years
ended December 31, 1997, 1996 and 1995, 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
$700, $3,000 and $3,500 for the years ended December 31, 1997, 1996
and 1995, respectively, and the Managing General Partner believes that
these costs are comparable to similar charges paid by the Partnership
to unrelated third parties.
Southwest Royalties, Inc., the Managing General Partner, was paid
$42,000 during 1997 and 40,896 during 1996 and 40,000 during 1995, as
an administrative fee for indirect general and administrative overhead
expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $54,454 and $79,012 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 1997 and 1996, respectively.
In addition, a director and officer of the Managing General Partner is
a partner in a law firm, with such firm providing legal services to
the Partnership approximating none, $90 and $300 for the years ended
December 31, 1997, 1996 and 1995, respectively.
6. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchasers, where the loss of one
would have a material adverse impact on the Partnership. Two
purchasers accounted for 71% of the Partnership's total oil and gas
production during 1997: Navajo Refining Company, Inc. 36%, and
American Processing 35%. Two purchasers accounted for 69% of the
Partnership's total oil and gas production during 1996: Navajo
Refining Company, Inc. 41%, and American Processing 28%. Two
purchasers accounted for 69% of the Partnership's total oil and gas
production during 1995: Navajo Refining Company, Inc. and American
Processing purchased 40% and 29%, respectively. All purchasers of the
Partnership's oil and gas production are unrelated third parties. In
the event any of these purchasers 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 sales of oil and gas production.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil (bbls) Gas (mcf)
---------- ---------
Proved developed and undeveloped
reserves -
January 1, 1995 168,000 1,707,000
Revisions of previous estimates (20,000) (80,000)
Production (17,000) (160,000)
------- ---------
December 31, 1995 131,000 1,467,000
Revisions of previous estimates 13,000 113,000
Production (15,000) (133,000)
------- ---------
December 31, 1996 129,000 1,447,000
Revisions of previous estimates (60,000) (552,000)
Production (11,000) (109,000)
------- ---------
December 31, 1997 58,000 786,000
======= =========
Proved developed reserves -
December 31, 1995 125,000 1,451,000
======= =========
December 31, 1996 122,000 1,428,000
======= =========
December 31, 1997 53,000 771,000
======= =========
All of the Partnership's reserves are located within the continental
United States.
*The reserve estimates were prepared as of January 1, 1998, by Donald
R. Creamer, P.E., an independent registered petroleum engineer. The
reserve estimates were made in accordance with guidelines established
by the Securities and Exchange Commission pursuant to Rule 4-10(a) of
Regulation S-X. Such guidelines require oil and gas reserve reports
be prepared under existing economic and operating conditions with no
provisions for price and cost escalation except by contractual
arrangements.
The New York Mercantile Exchange price at December 31, 1997 of $17.64
was used as the beginning basis for the oil price. Oil price
adjustments from $17.64 per barrel were made in the individual
evaluations to reflect oil quality, gathering and transportation
costs. The results are an average price received at the lease of
$16.38 per barrel in the preparation of the reserve report as of
January 1, 1998.
In the determination of the gas price, the New York Mercantile
Exchange price at December 31, 1997 of $2.26 was used as the beginning
basis. Gas price adjustments from $2.26 per Mcf were made in the
individual evaluations to reflect BTU content, gathering and
transportation costs and gas processing and shrinkage. The results
are an average price received at the lease of $2.15 per Mcf in the
preparation of the reserve report as of January 1, 1998.
Southwest Royalties Institutional Income Fund XI-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation.
In applying industry standards and procedures, the new data may cause
the previous estimates to be revised. This revision may increase or
decrease the earlier estimated volumes. Pertinent information
gathered during the year may include actual production and decline
rates, production from offset wells drilled to the same geologic
formation, increased or decreased water production, workovers, and
changes in lifting costs among others. Accordingly, reserve estimates
are often different from the quantities of oil and gas that are
ultimately recovered.
The Partnership has reserves which are classified a proved developed
producing, proved developed non-producing and proved undeveloped. All
of the proved reserves are included in the engineering reports which
evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to
farmout arrangements with the Managing General Partner or unrelated
third parties. Generally, the Partnership retains a carried interest
such as an overriding royalty interest under the terms of a farmout,
or receives cash.
Southwest Royalties Institutional Income Fund XI-B, 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, 1997, 1996 and 1995 is
presented below:
1997 1996 1995
---- ---- ----
Future cash inflows, net of
production and development
costs $ 1,104,000 4,409,000 2,650,000
10% annual discount for
estimated timing of cash
flows 313,000 1,692,000 985,000
--------- --------- ---------
Standardized measure of
discounted future net cash
flows $ 791,000 2,717,000 1,665,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
1997, 1996 and 1995 are as follows:
1997 1996 1995
---- ---- ----
Sales of oil and gas produced,
net of production costs $ (207,000) (580,000) (492,000)
Changes in prices and production costs (1,560,000) 1,642,000
220,000
Changes of production rates
(timing) and others 212,000 78,000 (303,000)
Revisions of previous
quantities estimates (643,000) (357,000) (240,000)
Accretion of discount 272,000 269,000 202,000
Discounted future net
cash flows -
Beginning of year 2,717,000 1,665,000 2,278,000
--------- --------- ---------
End of year $ 791,000 2,717,000 1,665,000
========= ========= =========
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.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
On June 9, 1997 Southwest Royalties, Inc. the Partnership's Managing
General Partner (Southwest Royalties, Inc.) dismissed Joseph Decosimo and
Company as the Partnership's independent accountants. The Managing General
Partner's Board of Directors approved the decision to change the
Partnership's independent accountants.
The reports of Joseph Decosimo and Company on the financial statements for
the past two fiscal years contained no adverse opinion or disclaimer of
opinion and were not qualified or modified as to uncertainty, audit scope
or accounting principle.
In connection with its audits for the two most recent fiscal years and
through June 9, 1997, there have been no disagreements with Joseph Decosimo
and Company on any matter of accounting principles or practices, financial
statements disclosure, or auditing scope or procedure, which disagreements
if not resolved to the satisfaction of Joseph Decosimo and Company would
have caused them to make reference thereto in their report on the financial
statements for such years.
The Registrant has requested that Joseph Decosimo and Company furnish it
with a letter addressed to the SEC stating whether or not is agrees with
the above statements. A copy of that letter is included as Exhibit 16 and
has been filled with the Securities and Exchange Commission.
Part III
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as
Managing General Partner. The names, ages, offices, positions and length
of service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below. Each director and executive officer serves for a
term of one year. The present directors of the Managing General Partner
have served in their capacity since the Company's formation in 1983.
Name Age Position
- -------------------- --- -----------------------------------
- --
H. H. Wommack, III 42 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 43 Secretary and Director
Bill E. Coggin 44 Vice President and Chief
Financial Officer
Phillip F. Hock, Jr. 54 Vice President, Exploration
Jon P. Tate 40 Vice President, Land and
Assistant Secretary
Joel D. Talley 36 Vice President, Acquisitions and
Exploitation Manager
R. Douglas Keathley 42 Vice President, Operations
J. Steven Person 39 Vice President, Marketing
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.
Phillip F. Hock, Jr., Vice President, Exploration, assumed his
responsibilities with the Managing General Partner as a geologist in
November 1993. Prior to joining the Managing General Partner, Mr. Hock was
employed four (4) years by Ramco Oil and Gas as Exploitation Manager (1989-
1993), Robinson Brothers Drilling Company as Exploration Manager (1980-
1984), and as petroleum geologist by several companies throughout his
career, Magic Circle Oil and Gas (1988-1989), Reading and Bates Petroleum
Company (1984-1988), and Exxon (1971-1980). Mr. Hock received a B. S. in
Geology from Morehead State University and a M. S. in Geology form the
University of New Mexico.
Jon P. Tate, Vice President, Land and Assistant Secretary, assumed his
responsibilities with the Managing General Partner in 1989. Prior to
joining the Managing General Partner, Mr. Tate was employed by C.F.
Lawrence & Associates, Inc., an independent oil and gas company, as Land
Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin
Landman's Association and received his B.B.S. degree from Hardin-Simmons
University.
Joel D. Talley, Vice President, Acquisitions and Exploitation Manager,
assumed his responsibilities with the Managing General Partner on July 15,
1996. Prior to joining the Managing General Partner, Mr. Talley was
employed for four (4) years by Merit Energy Company as Acquisitions Manager
and then as Region Manager over West Texas, New Mexico and Wyoming (1992-
1996) and eight (8) years by ARCO Oil & Gas Company in various engineering
positions (1984-1992). Mr. Talley received his B.S. in Mechanical
Engineering in 1984 from Texas A&M University.
R. Douglas Keathley, Vice President, Operations, assumed his
responsibilities with the Managing General Partner as a Production Engineer
in October, 1992. Prior to joining the Managing General Partner, Mr.
Keathley was employed for four (4) years by ARCO Oil & Gas Company as
senior drilling engineer working in all phases of well production (1988-
1992), eight (8) years by Reading & Bates Petroleum Company as senior
petroleum engineer responsible for drilling (1980-1988) and two (2) years
by Tenneco Oil Company as drilling engineer responsible for all phases of
drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum
Engineering in 1977 from the University of Oklahoma.
J. Steven Person, Vice President, Marketing, assumed his responsibilities
with the Managing General Partner as National Marketing Director in 1989.
Prior to joining the Managing General Partner, Mr. Person served as Vice
President of Marketing for CRI, Inc., and was associated with Capital
Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor
University in 1982 and an M.D.A. from Houston Baptist University in 1987.
Key Employees
Accounting and Administrative Officer - Debbie A. Brock, age 45, assumed
her position with the Managing General Partner in 1991. Prior to joining
the Managing General Partner, Ms. Brock was employed with Western Container
Corporation as Accounting Manager (1982-1990), Synthetic Industries
(Texas), Inc. as Accounting Manager (1976-1982) and held various accounting
positions in the manufacturing industry (1971-1975). Ms. Brock received a
B.B.A. from the University of Houston.
Controller - Robert A. Langford, age 48, assumed his responsibilities with
the Managing General Partner in 1992. Mr. Langford received his B.B.A.
degree in Accounting in 1975 from the University of Central Arkansas.
Prior to joining the Managing General Partner, Mr. Langford was employed
with Forest Oil Corporation as Corporate Coordinator, Regional Coordinator,
Accounting Manager. He held various other positions from 1982-1992 and
1976-1980 and was Assistant Controller of National Oil Company from 1980-
1982.
Financial Reporting Manager - Bryan Dixon, C.P.A., age 31, assumed his
responsibilities with the Managing General Partner in 1992. Mr. Dixon
received his B.B.A. degree in Accounting in 1988 from Texas Tech University
in Lubbock, Texas. Prior to joining the Managing General Partner, Mr.
Dixon was employed as a Senior Auditor with Johnson, Miller & Company from
1991-1992 and Audit Supervisor for Texas Tech University and the Texas Tech
University Health Sciences Center from 1988-1991.
Production Superintendent - Steve C. Garner, age 56, assumed his
responsibilities with the Managing General Partner as Production
Superintendent in July, 1989. Prior to joining the Managing General
Partner, Mr. Garner was employed 16 years by Shell Oil Company working in
all phases of oil field production as operations foreman, one and one-half
years with Petroleum Corporation of Delaware as Production Superintendent,
six years as an independent engineering consultant, and one year with
Citation Oil & Gas Corp. as a workover, completion and production foreman.
Mr. Garner has worked extensively in the Permian Basin oil field for the
last 25 years.
Tax Manager - Carolyn Cookson, age 41, assumed her position with the
Managing General Partner in April, 1989. Prior to joining the Managing
General Partner, Ms. Cookson was employed as Director of Taxes at C.F.
Lawrence & Associates, Inc. from 1983 to 1989, and worked in public
accounting at McCleskey, Cook & Green, P.C. from 1981 to 1983 and Deanna
Brady, C.P.A. from 1980 to 1981. She is a member of the Permian Basin
Chapter of the Petroleum Accountants' Society, and serves on its Board of
Directors and is liaison to the Tax Committee. Ms. Cookson received a
B.B.A. in accounting from New Mexico State University.
Investor Relations Manager - Sandra K. Flournoy, age 51, came to Southwest
Royalties, Inc. in 1988 from Parker & Parsley Petroleum, where she was
Assistant Manager of Investor Services and Broker/Dealer Relations for two
years. Prior to that, Ms. Flournoy was Administrative Assistant to the
Superintendent at Greenwood ISD for four years.
In certain instances, the Managing General Partner will engage professional
petroleum consultants and other independent contractors, including
engineers and geologists in connection with property acquisitions,
geological and geophysical analysis, and reservoir engineering. The
Managing General Partner believes that, in addition to its own "in-house"
staff, the utilization of such consultants and independent contractors in
specific instances and on an "as-needed" basis allows for greater
flexibility and greater opportunity to perform its oil and gas activities
more economically and effectively.
Item 11. Executive Compensation
The Partnership does not have any directors or executive officers. The
executive officers of the Managing General Partner do not receive any cash
compensation, bonuses, deferred compensation or compensation pursuant to
any type of plan, from the Partnership. The Managing General Partner
received $42,000 during 1997, $40,896 during 1996 and $40,000 during 1995,
as an annual administrative fee.
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 a nine percent interest in the
Partnership as a general partner.
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. 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 1997, the Managing General Partner received $42,000 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 $56,000 for administrative overhead
attributable to operating such properties during 1997.
Certain subsidiaries or affiliates of the Managing General Partner perform
various oilfield services for properties in which the Partnership owns an
interest. Such services aggregated approximately $700 for the year ended
December 31, 1997.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Reports of Independent Accountants
Balance Sheet
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 Royalties Institutional
Income Fund XI-B, L.P., dated August 24, 1993.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1993).
(b) Agreement of Limited
Partnership of Southwest Royalties Institutional
Income Fund XI-B, L.P., dated August 27, 1993.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1993).
16 Letter on Changes in Certifying Accountant
(Incorporated by reference from Partnership's Form 8-K
dated June 9, 1997.)
27 Financial Data Schedule
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 1997.
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 Royalties Institutional Income
Fund XI-B, L.P., a Delaware limited partnership
By: Southwest Royalties, Inc.,
Managing
General Partner
By: /s/ H. H. Wommack, III
-----------------------------
H. H. Wommack, III, President
Date: March 31, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III
-----------------------------------
H. H. Wommack, III, Chairman of the
Board, President, Chief Executive
Officer, Treasurer and Director
Date: March 31, 1998
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 31, 1998