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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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 of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
Midland, Texas 79701
(Address of principal executive offices)
(432) 686-9927
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all 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 whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2). Yes No 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 22.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly
used in the oil and gas industry that are used in this filing. All
volumes of natural gas referred to herein are stated at the legal
pressure base to the state or area where the reserves exit and at 60
degrees Fahrenheit and in most instances are rounded to the nearest
major multiple.
Bbl. One stock tank barrel, or 42 United States gallons liquid
volume.
Developmental well. A well drilled within the proved area of an
oil or natural gas reservoir to the depth of a stratigraphic horizon
known to be productive.
Exploratory well. A well drilled to find and produce oil or gas
in an unproved area to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or
to extend a known reservoir.
Farm-out arrangement. An agreement whereby the owner of the
leasehold or working interest agrees to assign his interest in
certain specific acreage to the assignee, retaining some interest,
such as an overriding royalty interest, subject to the drilling of
one (1) or more wells or other performance by the assignee.
Field. An area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition.
Mcf. One thousand cubic feet.
Net Profits Interest. An agreement whereby the owner receives a
specified percentage of the defined net profits from a producing
property in exchange for consideration paid. The net profits
interest owner will not otherwise participate in additional costs and
expenses of the property.
Oil. Crude oil, condensate and natural gas liquids.
Overriding royalty interest. Interests that are carved out of a
working interest, and their duration is limited by the term of the
lease under which they are created.
Present value and PV-10 Value. When used with respect to oil and
natural gas reserves, the estimated future net revenue to be
generated from the production of proved reserves, determined in all
material respects in accordance with the rules and regulations of the
SEC (generally using prices and costs in effect as of the date
indicated) without giving effect to non-property related expenses
such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization,
discounted using an annual discount rate of 10%.
Production costs. Costs incurred to operate and maintain wells
and related equipment and facilities, including depreciation and
applicable operating costs of support equipment and facilities and
other costs of operating and maintaining those wells and related
equipment and facilities.
Proved Area. The part of a property to which proved reserves
have been specifically attributed.
Proved developed oil and gas reserves. Proved developed oil and
gas reserves are reserves that can be expected to be recovered from
existing wells with existing equipment and operating methods.
Proved properties. Properties with proved reserves.
Proved reserves. The estimated quantities of crude oil, natural
gas, and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions.
Proved undeveloped reserves. Proved undeveloped oil and gas
reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
Reservoir. A porous and permeable underground formation
containing a natural accumulation of producible oil or gas that is
confined by impermeable rock or water barriers and is individual and
separate from other reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free
of costs of production.
Working interest. The operating interest that gives the owner
the right to drill, produce and conduct operating activities on the
property and a share of production.
Workover. Operations on a producing well to restore or increase
production.
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have
been prepared by the Registrant (herein also referred to as the
"Partnership") in accordance with generally accepted accounting
principles for interim financial information and with the
instructions to Form 10-Q and Rule 10-01 of Regulation S-X.
Accordingly, they do not include all of the information and footnotes
required by generally accepted accounting principles for complete
financial statements. In the opinion of management, all adjustments
necessary for a fair presentation have been included and are of a
normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the notes
thereto for the year ended December 31, 2003, which are found in the
Registrant's Form 10-K Report for 2003 filed with the Securities and
Exchange Commission. The December 31, 2003 balance sheet included
herein has been taken from the Registrant's 2003 Form 10-K Report.
Operating results for the three month period ended March 31, 2004 are
not necessarily indicative of the results that may be expected for
the full year.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Balance Sheets
March December
31, 31,
2004 2003
------ ------
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 149,763 187,199
Receivable from Managing 146,141 121,042
General Partner
Oklahoma withholding 94 94
prepayment
-------- --------
---- ----
Total current assets 295,998 308,335
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 4,242,36 4,242,36
7 7
Less accumulated
depreciation,
depletion and 3,630,91 3,618,91
amortization 4 4
-------- --------
---- ----
Net oil and gas 611,453 623,453
properties
-------- --------
---- ----
$ 907,451 931,788
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability - $ 96 58
distribution payable
-------- --------
---- ----
Asset retirement obligation 73,953 72,503
-------- --------
---- ----
Partners' equity:
General partner (553,462 (550,879
) )
Limited partners 1,386,86 1,410,10
4 6
-------- --------
---- ----
Total partners' equity 833,402 859,227
-------- --------
---- ----
$ 907,451 931,788
======= =======
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2004 2003
------ ------
Revenues
- -------------
Income from net profits $ 218,153 262,934
interests
Interest 347 232
Other 250 -
-------- --------
-- --
218,750 263,166
-------- --------
-- --
Expenses
- -------------
General and administrative 31,125 28,670
Depreciation, depletion and 12,000 18,000
amortization
Accretion of asset retirement 1,450 1,328
obligation
-------- --------
-- --
44,575 47,998
-------- --------
-- --
Net income before cumulative 174,175 215,168
effect
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See - (27,495)
Note 3
-------- --------
-- --
Net income $ 174,175 187,673
====== ======
Net income allocated to:
Managing General Partner $ 17,417 18,767
====== ======
Limited partners $ 156,758 168,906
====== ======
Per limited partner unit $ 10.45
before cumulative effect 12.91
Cumulative effect per limited - (1.65)
partner unit
-------- --------
-- --
Per limited partner unit $ 10.45
11.26
====== ======
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2004 2003
------ ------
Cash flows from operating
activities:
Cash received from income from $ 185,402 196,881
net profits interests
Cash paid to suppliers (23,473) (18,037)
Interest received 347 232
Other 250 -
-------- --------
---- ----
Net cash provided by operating 162,526 179,076
activities
-------- --------
---- ----
Cash flows used in financing
activities:
Distributions to partners (199,962 (150,378
) )
-------- --------
---- ----
Net (decrease) increase in cash (37,436) 28,698
and cash equivalents
Beginning of period 187,199 72,578
-------- --------
---- ----
End of period $ 149,763 101,276
======= =======
Reconciliation of net income to
net
cash provided by operating
activities:
Net income $ 174,175 187,673
Adjustments to reconcile net
income to net
cash provided by operating
activities:
Depreciation, depletion and 12,000 18,000
amortization
Accretion of asset retirement 1,450 1,328
obligation
Cumulative effect of change in
accounting
principle - SFAS No. 143 - 27,495
Increase in receivables (32,751) (66,053)
Increase in payables 7,652 10,633
-------- --------
---- ----
Net cash provided by operating $ 162,526 179,076
activities
======= =======
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption
of SFAS No. 143 $ - 38,901
======= =======
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. Revenues, costs
and expenses are allocated as follows:
Limited General
Partners Partners
-------- --------
--- ---
Interest income on capital 100% -
contributions
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and offering 100% -
costs (1)
Syndication costs 100% -
Amortization of organization 100% -
costs
Property acquisition costs 100% -
Gain/loss on property 90% 10%
disposition
Operating and administrative 90% 10%
costs (2)
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.
2. Summary of Significant Accounting Policies
The interim financial information as of March 31, 2004, and for
the three months ended March 31, 2004, is unaudited. Certain
information and footnote disclosures normally included in
financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted in
this Form 10-Q pursuant to the rules and regulations of the
Securities and Exchange Commission. However, in the opinion of
management, these interim financial statements include all the
necessary adjustments to fairly present the results of the
interim periods and all such adjustments are of a normal
recurring nature. The interim consolidated financial statements
should be read in conjunction with the Partnership's Annual
Report on Form 10-K for the year ended December 31, 2003.
3. Cumulative effect of change in accounting principle - SFAS No.
143
On January 1, 2003, the Partnership adopted Statement of
Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations ("SFAS No. 143"). Adoption of SFAS No.
143 is required for all companies with fiscal years beginning
after June 15, 2002. The new standard requires the Partnership
to recognize a liability for the present value of all legal
obligations associated with the retirement of tangible long-
lived assets and to capitalize an equal amount as a cost of the
asset and depreciate the additional cost over the estimated
useful life of the asset. On January 1, 2003, the Partnership
recorded additional costs, net of accumulated depreciation, of
approximately $38,901, a long term liability of approximately
$66,396 and a loss of approximately $27,495 for the cumulative
effect on depreciation of the additional costs and accretion
expense on the liability related to expected abandonment costs
of its oil and natural gas producing properties. At March 31,
2004, the asset retirement obligation was $73,953. The increase
in the asset retirement obligation from January 1, 2004 is due
to accretion expense of $1,450.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Subsequent Event
Subsequent to December 31, 2003, the Managing General Partner
announced that its Board of Directors had decided to explore a
merger or sale of the stock of the Company. The Board formed a
Special Committee of independent directors to oversee the sale
process. The Special Committee retained independent financial
and legal advisors to work closely with management to implement
the sale process.
On May 3, 2004, the Managing General Partner entered into a cash
merger agreement to sell all of its stock to Clayton Williams
Energy, Inc. The cash merger price is being negotiated, but is
expected to be approximately $45 per share. The transaction,
which is subject to approval by the Managing General Partner's
shareholders, is expected to close no later than May 21, 2004.
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
General
Southwest Royalties Institutional Income Fund VII-B, L.P. was
organized as a Delaware limited partnership on January 28, 1987. The
offering of such limited partnership interests began March 23, 1987
minimum capital requirements were met May 20, 1987 and concluded
December 1, 1987, with total limited partner contributions of
$7,500,000.
The Partnership was formed to acquire royalty and net profits
interests in producing oil and gas properties, to produce and market
crude oil and natural gas produced from such properties, and to
distribute the net proceeds from operations to the limited and
general partners. Net revenues from producing oil and gas properties
will not be reinvested in other revenue producing assets except to
the extent that production facilities and wells are improved or
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 farm-out arrangements, sales of
properties, and 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 partners is therefore expected to decline in later years based on
these factors.
Based on current conditions, management anticipates performing
development drilling projects and workovers during the years 2004 and
2005 to enhance production. The partnership may have an increase in
gas production volumes for the years 2004 and 2005, otherwise, the
partnership will most likely continue to experience the historical
production decline, which has approximated 15% per year.
Accordingly, if commodity prices remain unchanged, the Partnership
expects future earnings to decline due to anticipated production
declines.
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 sold.
In 2002, the Partnership changed methods of accounting for depletion
of capitalized costs from the units-of-revenue method to the units-of-
production method. The newly adopted accounting principle is
preferable in the circumstances because the units-of-production
method results in a better matching of the costs of oil and gas
production against the related revenue received in periods of
volatile prices for production as have been experienced in recent
periods. Additionally, the units-of-production method is the
predominant method used by full cost companies in the oil and gas
industry, accordingly, the change improves the comparability of the
Partnership's financial statements with its peer group.
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 March 31, 2004, 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.
The Partnership recognizes income from its net profits interest in
oil and gas property on an accrual basis, while the quarterly cash
distributions of the net profits interest are based on a calculation
of actual cash received from oil and gas sales, net of expenses
incurred during that quarterly period. If the net profits interest
calculation results in expenses incurred exceeding the oil and gas
income received during a quarter, no cash distribution is due to the
Partnership's net profits interest until the deficit is recovered
from future net profits. The Partnership accrues a quarterly loss on
its net profits interest provided there is a cumulative net amount
due for accrued revenue as of the balance sheet date. As of March
31, 2004, there were no timing differences, which resulted in a
deficit net profit interest.
Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost
method of accounting for its oil and gas properties. The full cost
method subjects companies to quarterly calculations of a "ceiling",
or limitation on the amount of properties that can be capitalized on
the balance sheet. If the Partnership's capitalized costs are in
excess of the calculated ceiling, the excess must be written off as
an expense.
The Partnership's discounted present value of its proved oil and
natural gas reserves is a major component of the ceiling calculation,
and represents the component that requires the most subjective
judgments. Estimates of reserves are forecasts based on engineering
data, projected future rates of production and the timing of future
expenditures. The process of estimating oil and natural gas reserves
requires substantial judgment, resulting in imprecise determinations,
particularly for new discoveries. Different reserve engineers may
make different estimates of reserve quantities based on the same
data. The Partnership's reserve estimates are prepared by outside
consultants. Quarterly reserve estimates are prepared by the
Managing General Partner's internal staff of engineers.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to
reflect updated information. However, there can be no assurance that
more significant revisions will not be necessary in the future. If
future significant revisions are necessary that reduce previously
estimated reserve quantities, it could result in a full cost property
writedown. In addition to the impact of these estimates of proved
reserves on calculation of the ceiling, estimates of proved reserves
are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment,
the associated prices of oil and natural gas reserves that are
included in the discounted present value of the reserves do not
require judgment. The ceiling calculation dictates that prices and
costs in effect as of the last day of the period are generally held
constant indefinitely. Because the ceiling calculation dictates that
prices in effect as of the last day of the applicable quarter are
held constant indefinitely, the resulting value is not indicative of
the true fair value of the reserves. Oil and natural gas prices have
historically been cyclical and, on any particular day at the end of a
quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true
fair value.
In 2002, the Partnership changed methods of accounting for depletion
of capitalized costs from the units-of-revenue method to the units-of-
production method. The newly adopted accounting principle is
preferable in the circumstances because the units-of-production
method results in a better matching of the costs of oil and gas
production against the related revenue received in periods of
volatile prices for production as have been experienced in recent
periods. Additionally, the units-of-production method is the
predominant method used by full cost companies in the oil and gas
industry, accordingly, the change improves the comparability of the
Partnership's financial statements with its peer group.
Results of Operations
A. General Comparison of the Quarters Ended March 31, 2004 and 2003
The following table provides certain information regarding
performance factors for the quarters ended March 31, 2004 and 2003:
Three Months
Ended Percenta
ge
March 31, Increase
2004 2003 (Decreas
e)
----- ----- --------
--
Average price per barrel of $ 32.17 1%
oil 31.78
Average price per mcf of gas $ 5.99 (1%)
6.06
Oil production in barrels 5,100 6,000 (15%)
Gas production in mcf 20,300 23,700 (14%)
Income from net profits $ 218,153 262,934 (17%)
interests
Partnership distributions $ 200,000 150,000 33%
Limited partner $ 180,000 135,000 33%
distributions
Per unit distribution to $ 12.00 33%
limited partners 9.00
Number of limited partner 15,000 15,000
units
Revenues
The Partnership's income from net profits interests decreased to $
218,153 from $262,934 for the quarters ended March 31, 2004 and 2003,
respectively, a decrease of 17%. The principal factors affecting the
comparison of the quarters ended March 31, 2004 and 2003 are as
follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended March 31, 2004 as compared to
the quarter ended March 31, 2003 by 1%, or $.39 per barrel,
resulting in an increase of approximately $2,000 in income from
net profits interests. Oil sales represented 57% of total oil
and gas sales during the quarter ended March 31, 2004 and 57%
during the quarter ended March 31, 2003.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 1%, or $.07 per mcf,
resulting in a decrease of approximately $1,400 in income from
net profits interests.
The net total increase in income from net profits interests due
to the change in prices received from oil and gas production is
approximately $600. The market price for oil and gas has been
extremely volatile over the past decade, and management expects a
certain amount of volatility to continue in the foreseeable
future.
2. Oil production decreased approximately 900 barrels or 15% during
the quarter ended March 31, 2004 as compared to the quarter ended
March 31, 2003, resulting in a decrease of approximately $28,600
in revenues.
Gas production decreased approximately 3,400 mcf or 14% during
the same period, resulting in a decrease of approximately $20,600
in income from net profits interests.
The total decrease in income from net profits interests due to
the change in production is approximately $49,200. The decline
in oil and gas volumes is the result of a lower net revenue
interest on a lease partially offset by larger volumes from a new
well on the same lease. The sale of two properties also
contributed to the decrease in oil volumes.
3. Lease operating costs and production taxes were 5% lower, or
approximately $3,800 less during the quarter ended March 31, 2004
as compared to the quarter ended March 31, 2003.
Costs and Expenses
Total costs and expenses decreased to $44,575 from $47,998 for the
quarters ended March 31, 2004 and 2003, respectively, a decrease of
7%. The decrease is a direct result of the decrease in depletion
expense, partially offset by an increase in accretion expense
associated with our long term liability related to expected
abandonment costs of our oil and natural gas properties and 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 9% or approximately $2,500 during
the quarter ended March 31, 2004 as compared to the quarter ended
March 31, 2003. The increase in general and administrative costs
is due primarily to an increase of approximately $1,660 in
quarterly accounting review fees.
2. Depletion expense decreased to $12,000 for the quarter ended
March 31, 2004 from $18,000 for the same period in 2003. This
represents a decrease of 33%. The contributing factor to the
decrease in depletion expense is in relation to the BOE depletion
rate for the quarter ended March 31, 2004, which was $1.41
applied to 8,483 BOE as compared to $1.81 applied to 9,950 BOE
for the same period in 2003.
Cumulative effect of change in accounting principle
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required
for all companies with fiscal years beginning after June 15, 2002.
The new standard requires the Partnership to recognize a liability
for the present value of all legal obligations associated with the
retirement of tangible long-lived assets and to capitalize an equal
amount as a cost of the asset and depreciate the additional cost over
the estimated useful life of the asset. On January 1, 2003, the
Partnership recorded additional costs, net of accumulated
depreciation, of approximately $38,901, a long term liability of
approximately $66,396 and a loss of approximately $27,495 for the
cumulative effect on depreciation of the additional costs and
accretion expense on the liability related to expected abandonment
costs of its oil and natural gas producing properties. At March 31,
2004, the asset retirement obligation was $73,953. The increase in
the asset retirement obligation from January 1, 2004 is due to
accretion expense of $1,450.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income
from 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
$162,500 in the quarter ended March 31, 2004 as compared to
approximately $179,100 in the quarter ended March 31, 2003.
Cash flows used in financing activities were approximately $200,000
in the quarter ended March 31, 2004 as compared to approximately
$150,400 in the quarter ended March 31, 2003. The only use in
financing activities was the distributions to partners.
Total distributions during the quarter ended March 31, 2004 were
$200,000 of which $180,000 was distributed to the limited partners
and $20,000 to the general partners. The per unit distribution to
limited partners during the quarter ended March 31, 2004 was $12.00.
Total distributions during the quarter ended March 31, 2003 were
$150,000 of which $135,000 was distributed to the limited partners
and $15,000 to the general partner. The per unit distribution to
limited partners during the quarter ended March 31, 2003 was $9.00.
The source for the 2004 distributions of $200,000 was oil and gas
operations of approximately $162,500, with the balance from available
cash on hand at the beginning of the period. The source for the 2003
distributions of $150,000 was oil and gas operations of approximately
$179,100, resulting in excess cash for contingencies or subsequent
distributions.
Cumulative cash distributions of $12,189,343 have been made to the
general and limited partners. As of March 31, 2004, $10,986,413 or
$732.43 per limited partner unit has been distributed to the limited
partners, representing a 100% return of the capital and a 46% return
on capital contributed.
As of March 31, 2004, the Partnership had approximately $295,900 in
working capital. The Managing General Partner knows of no unusual
contractual commitments. Although the partnership held many long-
lived properties at inception, because of the restrictions on
property development imposed by the partnership agreement, the
Partnership cannot develop its non producing properties, if any.
Without continued development, the producing reserves continue to
deplete. Accordingly, as the Partnership's properties have matured
and depleted, the net cash flows from operations for the partnership
has steadily declined, except in periods of substantially increased
commodity pricing. Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production.
As the properties continue to deplete, maintenance of properties and
administrative costs as a percentage of production are expected to
continue to increase.
Liquidity - Managing General Partner
As of December 31, 2003, the Managing General Partner is in violation
of several covenants pertaining to their Amended and Restated
Revolving Credit Agreement due June 1, 2006 and their Senior Second
Lien Secured Credit Agreement due October 15, 2008. Due to the
covenant violations, the Managing General Partner is in default under
their Amended and Restated Revolving Credit Agreement and the Senior
Second Lien Secured Credit Agreement, and all amounts due under these
agreements have been classified as a current liability on the
Managing General Partner's balance sheet at December 31, 2003. The
significant working capital deficit and debt being in default at
December 31, 2003, raise substantial doubt about the Managing General
Partner's ability to continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the
Managing General Partner announced its decision to explore a merger,
sale of the stock or other transaction involving the Managing General
Partner. The Board has formed a Special Committee of independent
directors to oversee the sales process. The Special Committee has
retained independent financial and legal advisors to work closely
with the management of the Managing General Partner to implement the
sales process. There can be no assurance that a sale of the Managing
General Partner will be consummated or what terms, if consummated,
the sale will be on.
On May 3, 2004, the Managing General Partner entered into a cash
merger agreement to sell all of its stock to Clayton Williams Energy,
Inc. The cash merger price is being negotiated, but is expected to
be approximately $45 per share. The transaction, which is subject to
approval by the Managing General Partner's shareholders, is expected
to close no later than May 21, 2004.
Recent Accounting Pronouncements
The EITF is considering two issues related to the reporting of oil
and gas mineral rights. Issue No. 03-O, "Whether Mineral Rights Are
Tangible or Intangible Assets," is whether or not mineral rights are
intangible assets pursuant to SFAS No. 141, "Business Combinations."
Issue No. 03-S, "Application of SFAS No. 142, Goodwill and Other
Intangible Assets, to Oil and Gas Companies," is, if oil and gas
drilling rights are intangible assets, whether those assets are
subject to the classification and disclosure provisions of SFAS No.
142. The Partnership classifies the cost of oil and gas mineral
rights as properties and equipment and believes that this is
consistent with oil and gas accounting and industry practice. The
disclosures required by SFAS Nos. 141 and 142 would be made in the
notes to the financial statements. There would be no effect on the
statement of income or cash flows as the intangible assets related to
oil and gas mineral rights would continue to be amortized under the
full cost method of accounting.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded
derivative instruments.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
As of the three months ended March 31, 2004, H.H. Wommack, III,
President and Chief Executive Officer of the Managing General
Partner, and Bill E. Coggin, Executive Vice President and Chief
Financial Officer of the Managing General Partner, evaluated the
effectiveness of the Partnership's disclosure controls and
procedures. Based on their evaluation, they believe that:
The disclosure controls and procedures of the Partnership were
effective in ensuring that information required to be disclosed
by the Partnership in the reports it files or submits under the
Exchange Act was recorded, processed, summarized and reported
within the time periods specified in the SEC's rules and forms;
and
The disclosure controls and procedures of the Partnership were
effective in ensuring that material information required to be
disclosed by the Partnership in the report it filed or submitted
under the Exchange Act was accumulated and communicated to the
Managing General Partner's management, including its President
and Chief Executive Officer and Chief Financial Officer, as
appropriate to allow timely decisions regarding required
disclosure.
Internal Control Over Financial Reporting
There has not been any change in the Partnership's internal control
over financial reporting that occurred during the three months ended
March 31, 2004 that has materially affected, or is reasonably likely
to materially affect, it internal control over financial reporting.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Certification of Chief Executive Officer Pursuant
to 18 U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
32.2 Certification of Chief Financial Officer Pursuant
to 18 U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the
quarter for which this report is filed.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant 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/ Bill E. Coggin
----------------------------------
- ----
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: May 14, 2004
SECTION 302 CERTIFICATION Exhibit 31.1
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties Institutional Income Fund VII-B, L.P.
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
3. Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this report;
4. The registrant's other certifying officer(s) and I are
responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15-15(e))
and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or
caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally
accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as
of the end of the period covered by this report based on such
evaluation; and
d) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have
disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent functions):
a) All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial reporting
which reasonably likely to adversely affect the registrant's ability
to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls over financial reporting.
Date: May 14, 2004 /s/ H. H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief
Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund VII-B, L.P.
SECTION 302 CERTIFICATION Exhibit 31.1
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties Institutional Income Fund VII-B, L.P.,
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
3. Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this report;
4. The registrant's other certifying officer(s) and I are
responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15-15(e))
and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or
caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally
accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as
of the end of the period covered by this report based on such
evaluation; and
d) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have
disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing
the equivalent functions):
a) All significant deficiencies and material weaknesses in the
design or operation of internal controls over financial reporting
which reasonably likely to adversely affect the registrant's ability
to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls over financial reporting.
Date: May 14, 2004 /s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund VII-B, L.P.
CERTIFICATION PURSUANT TO
Exhibit 32.1
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Royalties
Institutional Income Fund VII-B, L.P. (the "Company") on Form 10-Q
for the period ending March 31, 2004 as filed with the Securities and
Exchange Commission on the date hereof (the "Report"), I, H.H.
Wommack, III, Chief Executive Officer of the Managing General Partner
of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted
pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a)
or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operation
of the Company.
Date: May 14, 2004
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund VII-B, L.P.
CERTIFICATION PURSUANT TO Exhibit
32.2
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Royalties
Institutional Income Fund VII-B, L.P. (the "Company") on Form 10-Q
for the period ending March 31, 2004 as filed with the Securities and
Exchange Commission on the date hereof (the "Report"), I, Bill E.
Coggin, Chief Financial Officer of the Managing General Partner of
the Company, certify, pursuant to 18 U.S.C. 1350, as adopted
pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a)
or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operation
of the Company.
Date: May 14, 2004
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund VII-B, L.P.;