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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [Fee Required]
For the fiscal year ended December 31, 2000
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required]
For the transition period from to
Commission File Number 33-11576
Southwest Royalties Institutional Income Fund VII-B, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2165825
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 42. 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 35
Part III
10. Directors and Executive Officers of the Registrant 36
11. Executive Compensation 38
12. Security Ownership of Certain Beneficial Owners
and Management 38
13. Certain Relationships and Related Transactions 40
Part IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 41
Signatures 42
Part I
Item 1. Business
General
Southwest Royalties Institutional Income Fund VII-B, L.P. (the
"Partnership" or "Registrant") was organized as a Delaware limited
partnership on January 28, 1987. The offering of limited partnership
interests began March 23, 1987, reached minimum capital requirements May
20, 1987, and concluded December 1, 1987. The Partnership has no
subsidiaries.
The Partnership has expended its capital and acquired interests in
producing oil and gas properties. After such acquisitions, the Partnership
has produced and marketed the crude oil and natural gas produced from such
properties. In most cases, the Partnership purchased royalty or overriding
royalty interests and working interests in oil and gas properties that were
converted into net profits interests or other nonoperating interests. The
Partnership purchased either all or part of the rights and obligations
under various oil and gas leases.
The principal executive offices of the Partnership are located at 407 N.
Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner
of the Partnership, Southwest Royalties, Inc. (the "Managing General
Partner") and its staff of 92 individuals, together with certain
independent consultants used on an "as needed" basis, perform various
services on behalf of the Partnership, including the selection of oil and
gas properties and the marketing of production from such properties. 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, overriding royalty and net
profit interests in oil and gas properties located in Texas, New Mexico,
Oklahoma and Louisiana. All activities of the Partnership are confined to
the continental United States. All oil and gas produced from these
properties is sold to unrelated third parties in the oil and gas business.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. The prices received by
the Partnership for its oil and gas production depend upon numerous factors
beyond the Partnership's control, including competition, economic,
political and regulatory developments and competitive energy sources, and
make it particularly difficult to estimate future prices of oil and natural
gas.
The year 2000 was a record year for crude oil prices. The world energy
markets witnessed a continuation of the 1999 recovery seeing prices in the
U.S. peak at $37 per barrel in September. Increasing demand and depleting
inventories appeared to be the motivators in crude's dramatic rise. At the
beginning of 2000, U.S. crude oil inventories were approximately 16% lower
than at the beginning of 1999 and summer vacationers made it through a
travel season that saw gasoline prices top $2 per gallon in some U.S.
markets. The lack of crude oil inventory in the U.S. was also magnified by
the colder than normal winter that much of the country experienced.
However, several production increases from OPEC coupled with President
Clinton's release of 30 million barrels of oil from the U.S. Strategic
Petroleum Reserve in September contributed to the slow in prices toward the
end of the year. After averaging $30 per barrel for the year and over $32
from August through November, oil prices closed out the year 2000 at $26.80
per barrel.
Tighter supplies, rising demand, and the return of more seasonal summer and
winter weather catapulted spot gas prices in 2000 to the highest levels
since the market was deregulated in the mid-1980's. Average monthly spot
prices rose an astounding 72.9% over 1999 levels to average $3.77/MMBTU.
The climb in prices was fairly steady throughout the year, with the first-
quarter spot prices averaging $2.44/MMBtu. After the winter season ended
with a huge storage deficit of 306 BCF, a combination of factors
contributed further to the upward trend in spot prices. As the summer
temperatures heated up and the rate of storage injections remained
sluggish, competition for gas supplies became fierce between power
generators and gas utilities attempting to refill storage. Spot prices
really took off in the fourth quarter as competition for storage gas in the
waning days of the refill season became supercharged. And then came weeks
of early heating-season cold, which caused gas utilities to scramble to
meet the heating loads. A year of record high prices was capped off in
December, with spot prices averaging $6.14/MMBtu, more than two-and-a-half
times the previous five-year December average of $2.43/MMBtu.
Following is a table of the ratios of revenues received from oil and gas
production for the last three years:
Oil Gas
2000 73% 27%
1999 74% 26%
1998 74% 26%
As the table indicates, the majority of the Partnership's revenue is from
its oil production and Partnership revenues will be highly dependent upon
the future prices and demands for oil.
Seasonality of Business
Although the demand for natural gas is highly seasonal, with higher demand
in the colder winter months and in very hot summer months, the Partnership
has been able to sell all of its natural gas, either through contracts in
place or on the spot market at the then prevailing spot market price. As a
result, the volumes sold by the Partnership have not fluctuated materially
with the change of season.
Customer Dependence
No material portion of the Partnership's business is dependent on a single
purchaser, or a very few purchasers, where the loss of one would have a
material adverse impact on the Partnership. Four purchasers accounted for
77% of the Partnership's total oil and gas production during 2000: Phillips
66 Natural Gas Co. for 28%, Equiva Trading Company for 19%, BP Amoco for
17% and Plains Marketing LP for 13%. Four purchasers accounted for 74% of
the Partnership's total oil and gas production during 1999: Phillips 66
Natural Gas Co. for 27%, Equiva Trading Company for 19%, Amoco Production
for 17% and Scurlock Permian LLC. for 11%. Four purchasers accounted for
57% of the Partnership's total oil and gas production during 1998: Nustar
Joint Venture for 17%, Texaco Trading and Transport for 17%, Scurlock
Permian LLC for 12% and Enron Oil and Transportation, Inc. for 11%. 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 net profits or royalty 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 regulations. Many jurisdictions have periodically imposed
limitations on oil and gas production by restricting the rate of flow for
oil and gas wells below their actual capacity to produce and by imposing
acreage limitations for the drilling of wells. The federal government has
the power to permit increases in the amount of oil imported from other
countries and to impose pollution control measures.
Various aspects of the Partnership's oil and gas activities are regulated
by administrative agencies under statutory provisions of the states where
such activities are conducted and by certain agencies of the federal
government for operations on Federal leases. Moreover, certain prices at
which the Partnership may sell its natural gas production are controlled by
the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act
of 1989 and the regulations promulgated by the Federal Energy Regulatory
Commission.
Environmental - The Partnership's oil and gas activities are subject to
extensive federal, state and local laws and regulations governing the
generation, storage, handling, emission, transportation and discharge of
materials into the environment. Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties. This regulatory burden on the oil and gas industry increases
its cost of doing business and consequently affects its profitability. The
Managing General Partner is unable to predict what, if any, effect
compliance will have on the Partnership.
Industry Regulations and Guidelines - Certain industry regulations and
guidelines apply to the registration, qualification and operation of oil
and gas programs in the form of limited partnerships. The Partnership is
subject to these guidelines which regulate and restrict transactions
between the Managing General Partner and the Partnership.
The Partnership complies with these guidelines and the Managing General
Partner does not anticipate that continued compliance will have a material
adverse effect on Partnership operations.
Partnership Employees
The Partnership has no employees; however the Managing General Partner has
a staff of geologists, engineers, accountants, 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,
2000, there were 92 individuals directly employed by the Managing General
Partner in various capacities.
Item 2. Properties
In determining whether an interest in a particular 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, 2000, the Partnership possessed an interest in oil and
gas properties located in Cameron Parish of Louisiana; Eddy and Lea
Counties of New Mexico; Caddo, Garvin, Leflore, McClain and Pottawatomie
Counties of Oklahoma; Andrews, Dawson, Ector, Fisher, Gaines, Garza, Hale,
Hockley, Howard, Lamb, Leon, Loving, Martin, Midland, Pecos, Rusk, Scurry,
Stonewall, Tom Green, Upton, Ward and Winkler Counties of Texas. These
properties consist of various interests in approximately 2,653 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 2000, 1999 and 1998.
Significant Properties
The following table reflects the significant properties in which the
Partnership has an interest:
Date
Purchased No. of Proved Reserves*
Name and Location and Interest Wells Oil (bbls) Gas (mcf)
- ----------------- ------------ ----- ---------- ---------
Mobil Acquisition 10/88 at 2% 6 3,000 586,000
Pecos and Upton to 16% net
Counties, Texas profits interest
*Ryder Scott Petroleum Engineers prepared the reserve and present value
data for the Partnership's existing properties as of January 1, 2001. The
reserve estimates were made in accordance with guidelines established by
the Securities and Exchange Commission pursuant to Rule 4-10(a) of
Regulation S-X. Such guidelines require oil and gas reserve reports be
prepared under existing economic and operating conditions with no
provisions for price and cost escalation except by contractual
arrangements.
The New York Mercantile Exchange price at December 31, 2000 of $26.80 was
used as the beginning basis for the oil price. Oil price adjustments from
$26.80 per barrel were made in the individual evaluations to reflect oil
quality, gathering and transportation costs. The results are an average
price received at the lease of $24.99 per barrel in the preparation of the
reserve report as of January 1, 2001.
In the determination of the gas price, the New York Mercantile Exchange
price at December 31, 2000 of $9.78 was used as the beginning basis. Gas
price adjustments from $9.78 per Mcf were made in the individual
evaluations to reflect BTU content, gathering and transportation costs and
gas processing and shrinkage. The results are an average price received at
the lease of $9.95 per Mcf in the preparation of the reserve report as of
January 1, 2001.
As also discussed in Part II, Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations, oil and gas prices were
subject to frequent changes in 2000.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly with
respect to the quantity of oil or gas that any given property is capable of
producing. Estimates of oil and gas reserves are based on available
geological and engineering data, the extent and quality of which may vary
in each case and, in certain instances, may prove to be inaccurate.
Consequently, properties may be depleted more rapidly than the geological
and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than
previously estimated; thus an ultimately lower return for the Partnership.
Basic changes in past reserve estimates occur annually. As new data is
gathered during the subsequent year, the engineer must revise his earlier
estimates. A year of new information, which is pertinent to the estimation
of future recoverable volumes, is available during the subsequent year
evaluation. In applying industry standards and procedures, the new data
may cause the previous estimates to be revised. This revision may increase
or decrease the earlier estimated volumes. Pertinent information gathered
during the year may include actual production and decline rates, production
from offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs, among
others. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing, 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 Operations.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth
quarter of 2000 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters
Market Information
Limited partnership interests, or units, in the Partnership were initially
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. The Managing General Partner has become aware of certain limited and
sporadic transfers of units between limited partners and third parties, but
has no verifiable information regarding the prices at which such units have
been transferred. Further, a transferee may not become a substitute
limited partner without the consent of the Managing General Partner.
After completion of the Partnership's first full fiscal year of operations
and each year thereafter, the Managing General Partner has offered and will
continue to offer to purchase each limited partner's interest in the
Partnership, at a price based on tangible assets of the Partnership, plus
the present value of the future net revenues of proved oil and gas
properties, minus liabilities with a risk factor discount of up to one-
third which may be implemented in the sole discretion of the Managing
General Partner. However, the Managing General Partner's obligation to
purchase limited partner units is limited to an expenditure of an amount
not in excess of 10% of the total limited partner units initially
subscribed for by limited partners. In 2000, 1,063 limited partner units
were tendered to and purchased by the Managing General Partner at an
average base price of $121.97 per unit. In 1999, 203 limited partner units
were tendered to and purchased by the Managing General Partner at an
average base price of $63.70 per unit. In 1998, 343 limited partner units
were tendered to and purchased by the Managing General Partner at an
average base price of $90.55 per unit.
Number of Limited Partner Interest Holders
As of December 31, 2000, there were 769 holders of limited partner units in
the Partnership.
Distributions
Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and
Agreement of Limited Partnership "Net Cash Flow" is distributed to the
partners on a monthly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's investments in producing oil and gas
properties, less (i) General and Administrative Costs, (ii) Operating
Costs, and (iii) any reserves necessary to meet current and anticipated
needs of the Partnership, as determined in the sole discretion of the
Managing General Partner."
During 2000, quarterly distributions were made totaling $587,183, with
$528,465 distributed to the limited partners and $58,718 to the general
partners. For the year ended December 31, 2000, distributions of $35.23
per limited partner unit were made, based upon 15,000 limited partner units
outstanding. Distributions for 2000 increased significantly due to the
record high oil and gas prices received during the year. During 1999,
distributions were made totaling $344,786, with $282,086 distributed to the
limited partners and $62,700 to the general partners. For the year ended
December 31, 1999, distributions of $18.81 per limited partner unit were
made, based upon 15,000 limited partner units outstanding. During 1998,
distributions were made totaling $323,953, with $296,953 distributed to the
limited partners and $27,000 to the general partners. For the year ended
December 31, 1998, distributions of $19.80 per limited partner unit were
made, based upon 15,000 limited partner units outstanding.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2000, 1999, 1998, 1997 and 1996 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
-------------------------------------------------
- --------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Revenues $ 875,751 513,051 335,873 660,216 641,007
Net income (loss) 696,586 316,929 (31,771) 329,872 383,371
Partners' share
of net income (loss):
General partners 69,659 31,693 (3,177) 32,987 38,337
Limited partners 626,927 285,236 (28,594) 296,885 345,034
Limited partners'
net income (loss) per
unit 41.80 19.02 (1.91) 19.79 23.00
Limited partners'
cash distributions
per unit 35.23 20.79 19.80 33.42 32.22
Total assets $ 1,151,069 1,041,444 1,069,822 1,425,553 1,652,295
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
The Partnership was formed to acquire nonoperating 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 are not 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 thus depends 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 of 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 2001 to enhance production. The partnership may have an increase in
production volumes for the years 2001 and 2002, otherwise, the partnership
will most likely experience the historical production decline of
approximately 9% per year.
Results of Operations
A. General Comparison of the Years Ended December 31, 2000 and 1999
The following table provides certain information regarding performance
factors for the years ended December 31, 2000 and 1999:
Year Ended Percentage
December 31, Increase
2000 1999 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 28.69 17.53 64%
Average price per mcf of gas $ 4.09 2.26 81%
Oil production in barrels 28,700 29,920 (4%)
Gas production in mcf 73,600 81,520 (10%)
Income from net profits interests $ 867,334 509,251 70%
Partnership distributions $ 587,183 344,786 70%
Limited partner distributions $ 528,465 311,786 70%
Per unit distribution to limited partners $ 35.23 19.80 78%
Number of limited partner units 15,000 15,000
Revenues
The Partnership's income from net profits interests increased to $867,334
from $509,251 for the years ended December 31, 2000 and 1999, respectively,
an increase of 70%. 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 64%, or $11.16 per barrel, resulting in
an increase of approximately $320,300 in income from net profits
interests. Oil sales represented 73% of total oil and gas sales during
the year ended December 31, 2000 as compared to 74% 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 81%, or $1.83 per mcf, resulting in
an increase of approximately $134,700 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
$455,000. 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 1,220 barrels or 4% during the
year ended December 31, 2000 as compared to the year ended December 31,
1999, resulting in a decrease of approximately $21,400 in income from
net profits interests.
Gas production decreased approximately 7,920 mcf or 10% during the same
period, resulting in a decrease of approximately $17,900 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $39,300.
3. Lease operating costs and production taxes were 29% higher, or
approximately $57,600 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 one lease having
major repairs and maintenance such as downhole well repairs, 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.
Costs and Expenses
Total costs and expenses decreased to $179,165 from $196,122 for the years
ended December 31, 2000 and 1999, respectively, a decrease of 9%. The
decrease is the result of higher general and administrative expense,
partially offset by a decrease in depletion 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 4%
or approximately $4,000 during the year ended December 31, 2000 as
compared to the year ended December 31, 1999.
2. Depletion expense decreased to $62,000 for the year ended December 31,
2000 from $83,000 for the same period in 1999. 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.
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 $9,000 as of December 31, 1999.
Results of Operations
B. General Comparison of the Years Ended December 31, 1999 and 1998
The following table provides certain information regarding performance
factors for the years ended December 31, 1999 and 1998:
Year Ended Percentage
December 31, Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 17.53 12.70 38%
Average price per mcf of gas $ 2.26 1.95 16%
Oil production in barrels 29,920 35,800 (16%)
Gas production in mcf 81,520 83,200 (2%)
Income from net profits interests $ 509,251 332,758 53%
Partnership distributions $ 344,786 323,953 6%
Limited partner distributions $ 311,786 296,953 (5%)
Per unit distribution to limited partners $ 18.81 19.80 (5%)
Number of limited partner units 15,000 15,000
Revenues
The Partnership's income from net profits interests increased to $509,251
from $332,758 for the years ended December 31, 1999 and 1998, respectively,
an increase of 53%. The principal factors affecting the comparison of the
years ended December 31, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the year ended December 31, 1999 as compared to the
year ended December 31, 1998 by 38%, or $4.83 per barrel, resulting in
an increase of approximately $172,900 in income from net profits
interests. Oil sales represented 74% of total oil and gas sales during
the year ended December 31, 1999 as compared to 74% during the year
ended December 31, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 16%, or $.31 per mcf, resulting in
an increase of approximately $25,800 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
$198,700. 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 5,880 barrels or 16% during the
year ended December 31, 1999 as compared to the year ended December 31,
1998, resulting in a decrease of approximately $103,100 in income from
net profits interests.
Gas production decreased approximately 1,680 mcf or 2% during the same
period, resulting in a decrease of approximately $3,800 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $106,900. The decrease in
production is due primarily to property sales during 1998.
3. Lease operating costs and production taxes were 30% lower, or
approximately $84,900 less during the year ended December 31, 1999 as
compared to the year ended December 31, 1998. The decrease in lease
operating costs are primarily in relation to the drop in prices
experienced by the oil and gas economy throughout 1998 and the first
six months of 1999. The drop in revenue caused a decline in the
dollars necessary to perform workovers. Lower prices also caused some
wells to become uneconomical to operate and thus necessary to shut-in.
Additionally, the decrease in lease operating costs is partially due to
property sales in 1998.
Costs and Expenses
Total costs and expenses decreased to $196,122 from $367,644 for the years
ended December 31, 1999 and 1998, respectively, a decrease of 47%. The
decrease is the result of lower general and administrative expense and
depletion 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 decreased
13% or approximately $17,500 during the year ended December 31, 1999 as
compared to the year ended December 31, 1998. The decrease of general
and administrative costs were due in part to additional accounting
costs incurred in 1998 in relation to the outsourcing of K-1 tax
package preparation and a change in auditors requiring opinions from
both the predecessors and successor auditors. Additionally, the
Managing General Partner in its effort to cut back on general and
administrative costs whenever and wherever possible was able to reduce
the cost of reserve reports and K-1 tax package preparation during
1999.
3. Depletion expense decreased to $83,000 for the year ended December 31,
1999 from $237,000 for the same period in 1998. This represents a decrease
of 65%. 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 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, 2000 as compared
to 1999. 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 $111,000 as of
December 31, 1998.
C. Revenue and Distribution Comparison
Partnership net income (loss) for the years ended December 31, 2000, 1999
and 1998 was $696,586, $316,929 and $(31,771), respectively. Excluding the
effects of depreciation, depletion and amortization, net income for the
years ended December 31, 2000, 1999 and 1998 would have been $758,586,
$399,929 and $205,229, respectively. Correspondingly, Partnership
distributions for the years ended December 31, 2000, 1999 and 1998 were
$587,183, $344,786 and $323,953, respectively. These differences are
indicative of the changes in oil and gas prices, production and property
during 2000, 1999 and 1998.
The sources for the 2000 distributions of $587,200 were oil and gas
operations of approximately $680,921, resulting in excess cash for
contingencies or subsequent distributions. The source for the 1999
distributions of $344,786 was oil and gas operations of approximately
$306,020 and the change in oil and gas properties of approximately $14,900,
with the balance from available cash on hand at the beginning of the
period. The sources of the 1998 distributions of $323,953 were oil and gas
operations of approximately $284,200 and the change in oil and gas
properties of approximately $101,801, resulting in excess cash for
contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2000 were $587,183
of which $528,465 was distributed to the limited partners and $58,718 to
the general partners. The per unit distribution to limited partners during
the same period was $35.23. Total distributions during the year ended
December 31, 1999 were $344,786 of which $311,786 was distributed to the
limited partners and $33,000 to the general partners. The per unit
distribution to limited partners during the same period was $18.81. Total
distributions during the year ended December 31, 1998 were $323,953 of
which $296,953 was distributed to the limited partners and $27,000 to the
general partners. The per unit distribution to limited partners during the
same period was $19.80.
Since inception of the Partnership, cumulative monthly cash distributions
of $10,067,566 have been made to the partners. As of December 31, 2000,
$9,075,720 or $605.05 per limited partner unit, has been distributed to the
limited partners, representing a 121% 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.
Cash flows provided by operating activities were approximately $680,900 in
2000 compared to approximately $306,000 in 1999 and approximately $284,200
in 1998. The primary source of the 2000 cash flow from operating
activities was profitable operations.
The Partnership had no cash flows from investing activities in 2000. Cash
flows provided by investing activities were approximately $14,900 in 1999
and approximately $101,800 in 1998.
Cash flows used in financing activities were approximately $587,000 in 2000
compared to approximately $345,300 in 1999 and approximately $324,000 in
1998. The only use in financing activities was the distributions to
partners.
As of December 31, 2000, the Partnership had approximately $345,300 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenues generated from operations
are adequate to meet the needs of the Partnership.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Independent Auditors Report 20
Balance Sheets 21
Statements of Operations 22
Statement of Changes in Partners' Equity 23
Statements of Cash Flows 24
Notes to Financial Statements 26
INDEPENDENT AUDITORS REPORT
The Partners
Southwest Royalties Institutional
Income Fund VII-B, L.P.
(A Delaware Limited Partnership)
We have audited the accompanying balance sheets of Southwest Royalties
Institutional Income Fund VII-B, L.P. (the "Partnership") as of December
31, 2000 and 1999, and the related statements of operations, changes in
partners' equity and cash flows for each of the years in the three-year
period ended December 31, 2000. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Royalties
Institutional Income Fund VII-B, L.P. as of December 31, 2000 and 1999 and
the results of its operations and its cash flows for each of the years in
the three-year period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas
March 21, 2001
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2000 and 1999
2000 1999
---- ----
Assets
Current assets:
Cash and cash equivalents $ 155,801 61,841
Receivable from Managing General Partner 190,243 112,578
- --------- ---------
Total current assets
346,044 174,419
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 4,236,395 4,236,395
Less accumulated depreciation,
depletion and amortization
3,431,370 3,369,370
- --------- ---------
Net oil and gas properties
805,025 867,025
- --------- ---------
$
1,151,069 1,041,444
========= =========
Liabilities and Partners' Equity
Current liability - distribution payable $ 701 479
- --------- ---------
Partners' equity:
General partners (522,858) (533,799)
Limited partners 1,673,226 1,574,764
- --------- ---------
Total partners' equity
1,150,368 1,040,965
- --------- ---------
$
1,151,069 1,041,444
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Statements of Operations
Years ended December 31, 2000, 1999 and 1998
2000 1999
1998
---- ----
- ----
Revenues
Income from net profits interests $ 867,334 509,251 332,758
Interest 8,417 3,800 3,115
-------
- ------- -------
875,751
513,051 335,873
-------
- ------- -------
Expenses
General and administrative 117,165 113,122 130,644
Depreciation, depletion and amortization 62,000 83,000 237,000
-------
- ------- -------
179,165
196,122 367,644
-------
- ------- -------
Net income (loss) $ 696,586 316,929 (31,771)
=======
======= =======
Net income (loss) allocated to:
Managing General Partner $ 62,693 28,524 (2,859)
=======
======= =======
General partner $ 6,966 3,169 (318)
=======
======= =======
Limited partners $ 626,927 285,236 (28,594)
=======
======= =======
Per limited partner unit $ 41.80 19.02 (1.91)
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
Years ended December 31, 2000, 1999 and 1998
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, 1997 $ (502,315) 1,926,861 1,424,546
Net loss (3,177) (28,594) (31,771)
Distributions (27,000) (296,953) (323,953)
--------
- --------- ---------
Balance at December 31, 1998 (532,492) 1,601,314 1,068,822
Net income 31,693 285,236 316,929
Distributions (33,000) (311,786) (344,786)
--------
- --------- ---------
Balance at December 31, 1999 (533,799) 1,574,764 1,040,965
Net income 69,659 626,927 696,586
Distributions (58,718) (528,465) (587,183)
--------
- --------- ---------
Balance at December 31, 2000 $ (522,858) 1,673,226 1,150,368
========
========= =========
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Cash flows from operating activities:
Cash received from net profits interest $ 784,549 407,013 403,468
Cash paid to Managing General Partner
for administrative fees and
general
and administrative overhead
(112,045) (104,793)(122,383)
Interest received 8,417 3,800 3,115
--------
- -------- --------
Net cash provided by operating activities 680,921 306,020
284,200
--------
- -------- --------
Cash flows provided by investing activities:
Sale of oil and gas properties - 14,933 101,801
--------
- -------- --------
Cash flows used in financing activities:
Distributions to partners (586,961) (345,307)(323,960)
--------
- -------- --------
Net increase (decrease) in cash and
cash equivalents 93,960 (24,354) 62,041
Beginning of year 61,841 86,195 24,154
--------
- -------- --------
End of year $ 155,801 61,841 86,195
========
======== ========
(continued)
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Statements of Cash Flows, continued
Years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---- ---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities:
Net income (loss) $ 696,586 316,929 (31,771)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 62,000 83,000
237,000
(Increase) decrease in receivables (82,785) (102,238) 70,710
Increase in payables 5,120 8,329 8,261
-------
- ------- -------
Net cash provided by operating activities $ 680,921 306,020 284,200
=======
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund VII-B, L.P. was
organized under the laws of the state of Delaware on January 28, 1987,
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
sells its oil and gas production to a variety of purchasers with the
prices it receives being dependent upon the oil and gas economy.
Southwest Royalties, Inc. serves as the Managing General Partner and
H. H. Wommack, III, as the individual general partner. Revenues,
costs and expenses are allocated as follows:
Limited General
Partners Partners
-------- --------
Interest income on capital contributions 100% -
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and offering costs (1) 100% -
Syndication costs 100% -
Amortization of organization costs 100% -
Property acquisition costs 100% -
Gain/loss on property disposition 90% 10%
Operating and administrative costs (2) 90% 10%
Depreciation, depletion and amortization of
oil and gas properties 90% 10%
All other costs 90% 10%
(1)All organization costs in excess of 3% 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 3% of initial
capital contributions for such organization costs.
(2)Administrative costs in any year which exceed 2% of capital
contributions shall be paid by the Managing General Partner and
will be treated as a capital contribution.
Southwest Royalties Institutional Income Fund VII-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. As of December 31, 2000, 1999 and 1998,
the net capitalized costs did not exceed the estimated present value
of oil and gas reserves.
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 VII-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.
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 expended 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 expended. Liabilities for expenditures
of a non-capital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably
estimated.
Gas Balancing
The Partnership utilizes the sales method of accounting for gas-
balancing arrangements. Under this method the Partnership recognizes
sales revenue on all gas sold. As of December 31 2000, the
Partnership was under produced by 332 mcf of gas. As of December 31
1999, the Partnership was over produced by 1,214 mcf of gas. As of
December 31, 1998, there were no significant amounts of imbalance in
terms of units and value.
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes, the
Partnership's tax basis in its net oil and gas properties at December
31, 2000 and 1999 is $311,625 and $275,869 less than that shown on the
accompanying Balance Sheets in accordance with generally accepted
accounting principles.
Southwest Royalties Institutional Income Fund VII-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, 2000, 1999 and 1998, there were 15,000 limited
partner units outstanding held by 769, 871 and 893.
Concentrations of Credit Risk
The Partnership is subject to credit risk through trade receivables.
Although a substantial portion of its debtors' ability to pay is
dependent upon the oil and gas industry, credit risk is minimized due
to a large customer base. All partnership revenues are received by
the Managing General Partner and subsequently remitted to the
partnership and all expenses are paid by the Managing General Partner
and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair
value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Commitments and Contingent Liabilities
After completion of the Partnership's first full fiscal year of
operations and each year thereafter, the Managing General Partner has
offered and will continue to offer to purchase each limited partner's
interest in the Partnership, at a price based on tangible assets of
the Partnership, plus the present value of the future net revenues of
proved oil and gas properties, minus liabilities with a risk factor
discount of up to one-third which may be implemented in the sole
discretion of the Managing General Partner. However, the Managing
General Partner's obligation to purchase limited partner units is
limited to an expenditure of an amount not in excess of 10% of the
total limited partner units initially subscribed for by limited
partners.
The Partnership is subject to various federal, state and local
environmental laws and regulations which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 2000, the Partnership has not been fined, cited or
notified of any environmental violations and management is not aware
of any unasserted violations which would have a material adverse
effect upon capital expenditures, earnings or the competitive position
in the oil and gas industry. However, the Managing General Partner
does recognize by the very nature of its business, material costs
could be incurred in the near term to bring the Partnership into total
compliance. The amount of such future expenditures is not
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 VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As is usual in the industry and as provided
for in the operating agreement for each respective oil and gas
property in which the Partnership has an interest, the operator is
paid an amount for administrative overhead attributable to operating
such properties, with such amounts to Southwest Royalties, Inc. as
operator approximating $19,400, $19,400 and $20,600 for the years
ended December 31, 2000, 1999 and 1998, respectively. In addition,
the Managing General Partner and certain officers and employees may
have an interest in some of the properties that the Partnership also
participates.
Certain subsidiaries or affiliates of the Managing General Partner
perform various oilfield services for properties in which the
Partnership owns an interest. Such services aggregated approximately
$9,100, $3,500 and $2,800 and $500 for the years ended December 31,
2000, 1999 and 1998, respectively, and the Managing General Partner
believes that these costs are comparable to similar charges paid by
the Partnership to unrelated third parties.
Southwest Royalties, Inc., the Managing General Partner, was paid
$108,000 during 2000, 1999 and 1998 as an administrative fee for
indirect general and administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $190,200 and $112,600 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2000 and 1999, respectively.
In addition, a director and officer of the Managing General Partner is
a partner in a law firm, with such firm providing legal services to
the Partnership approximating $100, $200 and $100 for the year ended
December 31, 2000, 1999 and 1998, respectively.
5. Major Customers
No material portion of the Partnership's business is dependent on a
single purchaser, or a very few purchasers, where the loss of one
would have a material adverse impact on the Partnership. Four
purchasers accounted for 77% of the Partnership's total oil and gas
production during 2000: Phillips 66 Natural Gas Co. for 28%, Equiva
Trading Company for 19%, BP Amoco for 17% and Plains Marketing LP for
13%. Four purchasers accounted for 74% of the Partnership's total oil
and gas production during 1999: Phillips 66 Natural Gas Co. for 27%,
Equiva Trading Company for 19%, Amoco Production for 17% and Scurlock
Permian LLC. for 11%. Four purchasers accounted for 57% of the
Partnership's total oil and gas production during 1998: Nustar Joint
Venture for 17%, Texaco Trading and Transport for 17%, Scurlock
Permian LLC for 12% and Enron Oil and Transportation, Inc. for 11%.
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 VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil (bbls) Gas (mcf)
---------- ---------
Proved developed and undeveloped reserves -
January 1, 1998 284,000 655,000
Sales of reserves in place (29,000) (2,000)
Revisions of previous estimates (71,000) 102,000
Production (36,000) (83,000)
------- --------
December 31, 1998 148,000 672,000
Sales of reserves in place (2,000) -
Revisions of previous estimates 121,000 272,000
Production (30,000) (82,000)
------- --------
December 31, 1999 237,000 862,000
Revisions of previous estimates 9,000 145,000
Production (29,000) (74,000)
------- --------
December 31, 2000 217,000 926,000
======= ========
Proved developed reserves -
December 31, 1998 145,000 661,000
======= ========
December 31, 1999 234,000 851,000
======= ========
December 31, 2000 214,000 926,000
======= ========
All of the Partnership's reserves are located within the continental
United States.
*Ryder Scott Petroleum Engineers prepared the reserve and present
value data for the Partnership's existing properties as of January 1,
2001. The reserve estimates were made in accordance with guidelines
established by the Securities and Exchange Commission pursuant to Rule
4-10(a) of Regulation S-X. Such guidelines require oil and gas
reserve reports be prepared under existing economic and operating
conditions with no provisions for price and cost escalation except by
contractual arrangements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil and Gas Reserves (unaudited) - continued
The New York Mercantile Exchange price at December 31, 2000 of $26.80
was used as the beginning basis for the oil price. Oil price
adjustments from $26.80 per barrel were made in the individual
evaluations to reflect oil quality, gathering and transportation
costs. The results are an average price received at the lease of
$24.99 per barrel in the preparation of the reserve report as of
January 1, 2001.
In the determination of the gas price, the New York Mercantile
Exchange price at December 31, 2000 of $9.78 was used as the beginning
basis. Gas price adjustments from $9.78 per Mcf were made in the
individual evaluations to reflect BTU content, gathering and
transportation costs and gas processing and shrinkage. The results
are an average price received at the lease of $9.95 per Mcf in the
preparation of the reserve report as of January 1, 2001.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation. In applying industry
standards and procedures, the new data may cause the previous
estimates to be revised. This revision may increase or decrease the
earlier estimated volumes. Pertinent information gathered during the
year may include actual production and decline rates, production from
offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs,
among others. Accordingly, reserve estimates are often different from
the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed
producing, 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 VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil & Gas Reserves (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2000, 1999 and 1998 is
presented below:
2000 1999 1998
---- ---- ----
Future cash inflows, net of
production and development
costs $ 10,895,000 5,122,000 1,630,000
10% annual discount for
estimated timing of cash
flows (5,164,000) 2,102,000 623,000
--------- --------- ---------
Standardized measure of
discounted future net cash
flows $ 5,731,000 3,020,000 1,007,000
========= ========= =========
The principal sources of change in the standardized measure of
discounted future net cash flows for the years ended December 31,
2000, 1999 and 1998 are as follows:
2000 1999 1998
---- ---- ----
Sales of oil and gas produced,
net of production costs $
(868,000) (509,000)(333,000)
Changes in prices and production costs 2,997,000 1,068,000
(797,000)
Changes of production rates
(timing) and others (230,000)
46,000 (72,000)
Sales of minerals in place - (9,000) (96,000)
Revisions of previous
quantities estimates 510,000
1,316,000 (206,000)
Accretion of discount 302,000 101,000 228,000
Discounted future net
cash flows -
Beginning of year 3,020,000 1,007,000 2,283,000
--------- --------- ---------
End of year $ 5,731,000 3,020,000 1,007,000
========= ========= =========
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 Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Selected Quarterly Financial Results - (unaudited)
Quarter
----------------------------------------------
First Second Third Fourth
------ ------- ------ ------
2000:
Total revenues $ 197,075 207,548 240,676 230,452
Total expenses 54,686 44,060 50,425 29,994
Net income 142,389 163,488 190,251 200,458
Net income per limited
partners unit 8.54 9.81 11.42 12.03
1999:
Total revenues $ 85,471 111,516 145,645 170,419
Total expenses 57,588 50,693 38,972 48,869
Net income 27,883 60,823 106,673 121,550
Net income per limited
partners unit 1.67 3.65 6.40 7.29
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None
Part III
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as
Managing General Partner. The names, ages, offices, positions and length
of service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below. Each director and executive officer serves for a
term of one year. The present directors of the Managing General Partner
have served in their capacity since the Company's formation in 1983.
Name Age Position
- -------------------- --- -----------------------------------
- -------
H. H. Wommack, III 45 Chairman of the Board,
President,
Chief Executive Officer, Treasurer
and Director
H. Allen Corey 44 Secretary and Director
Bill E. Coggin 46 Vice President and Chief
Financial Officer
J. Steven Person 42 Vice President, Marketing
Paul L. Morris 59 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive
Officer, Treasurer, principal stockholder and a director of the Managing
General Partner, and has served as its President since the Company's
organization in August, 1983. Prior to the formation of the Company, Mr.
Wommack was a self-employed independent oil producer engaged in the
purchase and sale of royalty and working interests in oil and gas leases,
and the drilling of exploratory and developmental oil and gas wells. Mr.
Wommack holds a J.D. degree from the University of Texas from which he
graduated in 1980, and a B.A. from the University of North Carolina in
1977.
H. Allen Corey, a founder of the Managing General Partner, has served as
the Managing General Partner's secretary and a director since its
inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew
pub restaurant chain based in the Southeast. Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga, Tennessee. He is currently of counsel to the law firm of
Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga,
Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University
Law School and B.A. degree from the University of North Carolina at Chapel
Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with
the Managing General Partner since 1985. Mr. Coggin was Controller for Rod
Ric Corporation of Midland, Texas, an oil and gas drilling company, during
the latter part of 1984. He was Controller for C.F. Lawrence & Associates,
Inc., an independent oil and gas operator also of Midland, Texas during the
early part of 1984. Mr. Coggin taught public school for four years prior
to his business experience. Mr. Coggin received a B.S. in Education and a
B.B.A. in Accounting from Angelo State University.
J. Steven Person, Vice President, Marketing, assumed his responsibilities
with the Managing General Partner as National Marketing Director in 1989.
Prior to joining the Managing General Partner, Mr. Person served as Vice
President of Marketing for CRI, Inc., and was associated with Capital
Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor
University in 1982 and an M.B.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings,
Inc. since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States. Prior to
his position with Wagner & Brown, Mr. Morris served as President of Banner
Energy and in various managerial positions with the Columbia Gas System,
Inc.
Key Employees
Jon P. Tate, Vice President, Land and Assistant Secretary, age 43, assumed
his responsibilities with the Managing General Partner in 1989. Prior to
joining the Managing General Partner, Mr. Tate was employed by C.F.
Lawrence & Associates, Inc., an independent oil and gas company, as Land
Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin
Landman's Association and American Association of Petroleum Landmen. Mr.
Tate received his B.B.S. degree from Hardin-Simmons University.
R. Douglas Keathley, Vice President, Operations, age 45, assumed his
responsibilities with the Managing General Partner as a Production Engineer
in October, 1992. Prior to joining the Managing General Partner, Mr.
Keathley was employed for four (4) years by ARCO Oil & Gas Company as
senior drilling engineer working in all phases of well production (1988-
1992), eight (8) years by Reading & Bates Petroleum Company as senior
petroleum engineer responsible for drilling (1980-1988) and two (2) years
by Tenneco Oil Company as drilling engineer responsible for all phases of
drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum
Engineering in 1977 from the University of Oklahoma.
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 $108,000 during 2000, 1999 and 1998, respectively, 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. Through repurchase offers to the limited
partners, the Managing General Partner also owns 3,017.5 limited partner
units, a 20.1% limited partner interest. The Managing General Partner's
total percentage interest ownership in the Partnership is 27.1%.
No officer or director of the Managing General Partner owns Units in the
Partnership. H. H. Wommack, III, as the individual general partner of the
Partnership, owns a one percent interest as a general partner. The
officers and directors of the Managing General Partner are considered
beneficial owners of the limited partner units acquired by the Managing
General Partner by virtue of their status as such. A list of beneficial
owners of limited partner units, acquired by the Managing General Partner,
is as follows:
Amount and
Nature of Percent
Name and Address of Beneficial of
Title of Class Beneficial Owner Ownership Class
- ------------------- --------------------------- --------------- -------
Limited Partnership Southwest Royalties, Inc. Directly Owns 20.1%
Interest Managing General Partner 3,017.5 Units
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns 20.1%
Interest Chairman of the Board, 3,017.5 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 20.1%
Interest Secretary and Director of 3,017.5 Units
Southwest Royalties, Inc.,
the Managing General
Partner
633 Chestnut Street
Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns 20.1%
Interest Vice President and CFO of 3,017.5 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns 20.1%
Interest Vice President, Marketing of 3,017.5 Units
Southwest Royalties, Inc.,
the Managing General
Partner
407 N. Big Spring Street
Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns 20.1%
Interest Director, of Southwest 3,017.5 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 Relationship and Related Transactions
In 2000, the Managing General Partner received $108,000 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 net profits interest. Certain properties
in which the Partnership has an interest are operated by the Managing
General Partner, who was paid approximately $19,400 for administrative
overhead attributable to operating such properties during 2000.
Certain subsidiaries or affiliates of the Managing General Partner perform
various oilfield services for properties in which the Partnership owns an
interest. Such services aggregated approximately $9,100 for the year ended
December 31, 2000.
The law firm of Baker, Donelson, Bearman & Caldwell of which H. Allen
Corey, an officer and director of the Managing General Partner, is a
partner, is counsel to the Partnership. Legal services rendered by Baker,
Donelson, Bearman & Caldwell to the Partnership during 2000 were
approximately $100, which constitutes an immaterial portion of that firm's
business.
In the opinion of management, the terms of the above transactions are
similar to ones with unaffiliated third parties.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Independent Auditors Report
Balance Sheets
Statements of Operations
Statement of Changes in Partners' Equity
Statements 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 VII-B, L.P., dated January 28, 1987.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1988.)
(b) Agreement of Limited
Partnership of Southwest Royalties Institutional
Income Fund VII-B, L.P. dated May 20, 1987.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1988.)
(c) Certificate of Amendment of
Limited Partnership of Southwest Royalties
Institutional Income Fund VII-B, L.P., dated July
21, 1987. (Incorporated by reference from
Partnership's Form 10-K for the fiscal year ended
December 31, 1988.)
27 Financial Data Schedule
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the
quarter ended December 31, 2000.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Partnership has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Royalties Institutional Income Fund
VII-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 30, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III
-----------------------------------
H. H. Wommack, III, Chairman of the
Board, President, Chief Executive
Officer, Treasurer and Director
Date: March 30, 2001
By: /s/ H. Allen Corey
-----------------------------
H. Allen Corey, Secretary and
Director
Date: March 30, 2001