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FORM 10-Q/A
AMENDMENT NO. 1
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, 2003
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 No _X_
The total number of pages contained in this report is 24.
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, 2002, which are found in the
Registrant's Form 10-K/A Report for 2002 filed with the Securities
and Exchange Commission. The December 31, 2002 balance sheet
included herein has been taken from the Registrant's 2002 Form 10-K/A
Report. Operating results for the three month period ended March 31,
2003 are not necessarily indicative of the results that may be
expected for the full year.
Introductory Note - Statement of Financial Accounting Standard No.
143
The Partnership implemented SFAS No. 143 effective January 1, 2003
(See Note 3) to the Partnership's financial statements. Subsequent
to the filing of the Partnership's Quarterly Report on Form 10-Q, the
Partnership discovered an omission in the calculation of the asset
retirement liability and therefore has restated it's unaudited
condensed financial statements for the period ended March 31, 2003 as
described in Note 5 to the Partnership's financial statements.
Introductory Note - Depletion Method
During the fourth quarter of 2002, the Partnership changed its method
of providing for depletion from the units-of-revenue method to the
units-of-production method as described in Notes 4 and 6 to the
Partnership's financial statements.
This change in depletion method was applied as a cumulative effect of
a change in accounting principle effective as of January 1, 2002.
The unaudited condensed financial statements of the Partnership for
the period ended March 31, 2002, included herein, have been restated
(as described in Notes 4 and 6 to the Partnership's financial
statements) using the new depletion method and differ from those
previously issued in the Partnership's Quarterly Report on Form 10-Q
for the period ended March 31, 2002.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Balance Sheets
March December
31, 31,
2003 2002
(Restate
d)
------ ------
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 101,276 72,578
Receivable from Managing 190,479 135,059
General Partner
-------- --------
---- ----
Total current assets 291,755 207,637
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 4,257,78 4,236,33
1 5
Less accumulated
depreciation,
depletion and 3,575,91 3,575,37
amortization 5 0
-------- --------
---- ----
Net oil and gas 681,866 660,965
properties
-------- --------
---- ----
$ 973,621 868,602
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability - $ 90 468
distribution payable
-------- --------
---- ----
Other long term liabilities 67,724 -
-------- --------
---- ----
Partners' equity:
General partners (547,315 (551,082
) )
Limited partners 1,453,12 1,419,21
2 6
-------- --------
---- ----
Total partners' equity 905,807 868,134
-------- --------
---- ----
$ 973,621 868,602
======= =======
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2003 2002
(Restate (Restate
d) d)
------ ------
Revenues
- -------------
Income from net profits $ 262,934 137,418
interests
Interest 232 473
-------- --------
-- --
263,166 137,891
-------- --------
-- --
Expenses
- -------------
General and administrative 28,670 28,644
Depreciation, depletion and 18,000 17,000
amortization
Accretion 1,328 -
-------- --------
-- --
47,998 45,644
-------- --------
-- --
Net income before cumulative 215,168 92,247
effect
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See (27,495) -
Note 3
Cumulative effect of change in
accounting principle
- change in depletion method - - 16,000
See Note 4
-------- --------
-- --
Net income $ 187,673 108,247
====== ======
Net income allocated to:
Managing General Partner $ 18,767 9,742
====== ======
General partner $ - 1,083
====== ======
Limited partners $ 168,906 97,422
====== ======
Per limited partner unit $ 12.90
before cumulative effect 5.53
Cumulative effects per (1.64) .96
limited partner unit
-------- --------
-- --
Per limited partner unit $ 11.26
6.49
====== ======
Pro forma amounts assuming
changes are applied
retroactively (See Note 3):
Net income before cumulative $ - 91,025
effect
====== ======
Per limited partner unit $ - 5.46
(15,000.0)
====== ======
Net income $ - 107,025
====== ======
Per limited partner unit $ - 6.42
(15,000.0)
====== ======
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2003 2002
(Restate (Restate
d) d)
------ ------
Cash flows from operating
activities:
Cash received from income from $ 196,881 110,019
net profits interests
Cash paid to suppliers (18,037) (28,608)
Interest received 232 473
-------- --------
---- ---
Net cash provided by operating 179,076 81,884
activities
-------- --------
---- ---
Cash flows used in financing
activities:
Distributions to partners (150,378 (149,323
) )
-------- --------
---- ----
Net increase (decrease) in cash 28,698 (67,439)
and cash equivalents
Beginning of period 72,578 118,007
-------- --------
---- ----
End of period $ 101,276 50,568
======= =======
Reconciliation of net income to
net
cash provided by operating
activities:
Net income $ 187,673 108,247
Adjustments to reconcile net
income to net
cash provided by operating
activities:
Depreciation, depletion and 18,000 17,000
amortization
Accretion 1,328 -
Cumulative effect of change in
accounting
principle - SFAS No. 143 27,495 -
Cumulative effect of change in
accounting
principle - change in depletion - (16,000)
method
Increase in receivables (66,053) (27,399)
Increase in payables 10,633 36
-------- --------
---- ----
Net cash provided by operating $ 179,076 81,884
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 and H. H. Wommack,
III, as the individual general partner. Effective December 31,
2001, Mr. Wommack sold his general partner interest to 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, 2003, and for
the three months ended March 31, 2003, 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/A 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/A for the year ended December 31, 2002.
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
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,
2003, the asset retirement obligation was $67,724, and the
increase in the balance from January 1, 2003 of $1,328 is due to
accretion expense. The pro forma amounts for the three months
ended March 31, 2002, which are presented on the face of the
statements of operations, reflect the effect of retroactive
application of SFAS No. 143.
4. Cumulative effect of change in accounting principle - change in
depletion method
In the fourth quarter of 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. The
Partnership adopted the units-of-production method through the
recording of a cumulative effect of a change in accounting
principle in the amount of $16,000 effective as of January 1,
2002. The Partnership's depletion for the three months ended
March 31, 2003 and 2002 has been calculated using the units-of-
production method. The effect of the change on the three months
ended March 31, 2002 was to decrease income before cumulative
effect of a change in accounting principle by $5,000 ($.30 per
limited partner unit) and increase net income by $11,000 ($.66
per limited partner unit).
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. March 31, 2003 Restatement
On January 1, 2003, the Partnership adopted Statement of
Financial Accounting Standards No. 143 as described in Note 3.
Subsequent to the issuance of the Partnership's Quarterly Report
on Form 10-Q for the three months ended March 31, 2003, the
Partnership determined that it did not properly discount the
estimated future plugging liability to its present value.
This change in the calculation used to determine the amount of
the Partnership's asset retirement liability under SFAS No. 143
resulted in a decrease in the Partnership's previously reported
other long term liability of $85,131 from $152,855 to $67,724 as
of March 31, 2003 and did not effect the Partnership's 2003 cash
flows from operations, investing or financing activities.
The change had the following effects on the Statement of
Operations for the three months ended March 31, 2003. (Periods
prior to 2003 were not affected by the change).
Restated Previously
Reported
Accretion $1,328 2,977
Income before cumulative effect 215,168 214,499
Cumulative effect of change in (27,495) (110,635)
accounting principle
Net income 187,673 103,864
Net income allocated to:
Managing General Partner 18,767 10,386
General partner - -
Limited partners 168,906 93,478
Income per limited partner
unit before
Cumulative effect 12.90 6.23
Cumulative effect per (1.64) -
limited partner unit
Net income per limited 11.26 6.23
partner unit
Southwest Royalties Institutional Income Fund VII-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. March 31, 2002 Restatement
During the fourth quarter of 2002, the Partnership changed its
method of providing for depletion from the units-of-revenue
method to the units-of-production method as described in Note 4.
Subsequent to the issuance of the Partnership's Quarterly Report
on Form 10-Q for the three months ended March 31, 2003, the
Partnership determined that the above change in accounting
method should have been adopted by the Partnership as a
cumulative effect of a change in accounting principle effective
as of January 1, 2002. The Partnership had previously applied
the change in the method of providing for depletion
prospectively as of October 1, 2002.
This change in the method used to implement the Partnership's
change in the manner in which it determines depletion resulted
in an increase in the Partnership's previously reported net oil
and gas properties of $11,000 from $649,965 to $660,965 as of
December 31, 2002 and did not effect the Partnership's 2002 cash
flows from operations, investing or financing activities.
The change had the following effects on the Statement of
Operations for the three months ended March 31, 2002.
Restated Previously
Reported
Depreciation, depletion and $17,000 12,000
amortization
Income before cumulative effect 92,247 97,247
Cumulative effect of change in 16,000 -
accounting principle
Net income 108,247 97,247
Net income allocated to:
Managing General Partner 9,742 8,753
General partner 1,083 972
Limited partners 97,422 87,522
Income per limited partner
unit before
cumulative effect 5.53 5.83
Cumulative effect per .96 -
limited partner unit
Net income per limited 6.49 5.83
partner unit
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 fluctuate in later years based
on these factors.
Based on current conditions, management anticipates performing
development drilling projects and workovers during the years 2003 and
2004 to enhance production. The partnership may have an increase in
production volumes for the years 2003 and 2004, otherwise, the
partnership will most likely experience the historical production
decline, which has approximated 15% per year.
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.
In the fourth quarter of 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. The effect
of this change in method was to increase depletion expense for the
three months ended March 31, 2002 by $5,000 and increase net income
for the three months ended March 31, 2002 by $11,000. See Note 4 of
the notes to the Partnership's financial statements.
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, 2003, 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, 2003, 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 on an annual basis
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 the fourth quarter of 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. The effect
of this change in method was to increase depletion expense for the
three months ended March 31, 2002 by $5,000 and increase net income
for the three months ended March 31, 2002 by $11,000.
Results of Operations
A. General Comparison of the Quarters Ended March 31, 2003 and 2002
The following table provides certain information regarding
performance factors for the quarters ended March 31, 2003 and 2002:
Three Months
Ended Percenta
ge
March 31, Increase
2003 2002 (Decreas
e)
----- ----- --------
--
Average price per barrel of $ 31.78 62%
oil 19.60
Average price per mcf of gas $ 6.06 205%
1.99
Oil production in barrels 6,000 7,400 (19%)
Gas production in mcf 23,700 22,800 4%
Income from net profits $ 262,934 137,418 91%
interests
Partnership distributions $ 150,000 150,000 -
Limited partner $ 135,000 135,000 -
distributions
Per unit distribution to $ 9.00 -
limited partners 9.00
Number of limited partner 15,000 15,000
units
Revenues
The Partnership's income from net profits interests increased to
$262,934 from $137,418 for the quarters ended March 31, 2003 and
2002, respectively, an increase of 91%. The principal factors
affecting the comparison of the quarters ended March 31, 2003 and
2002 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended March 31, 2003 as compared to
the quarter ended March 31, 2002 by 62%, or $12.18 per barrel,
resulting in an increase of approximately $73,100 in income from
net profits interests. Oil sales represented 57% of total oil
and gas sales during the quarter ended March 31, 2003 and 76%
during the quarter ended March 31, 2002.
The average price for an mcf of gas received by the Partnership
increased during the same period by 205%, or $4.07 per mcf,
resulting in an increase of approximately $96,500 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 $169,600. 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 1,400 barrels or 19%
during the quarter ended March 31, 2003 as compared to the
quarter ended March 31, 2002, resulting in a decrease of
approximately $27,400 in revenues.
Gas production increased approximately 900 mcf or 4% during the
same period, resulting in an increase of approximately $1,800 in
income from net profits interests.
The total net decrease in income from net profits interests due
to the change in production is approximately $25,600. The
decrease in oil production is due to a non-operated lease
experiencing a sharp natural decline.
3. Lease operating costs and production taxes were 35% higher, or
approximately $18,400 more during the quarter ended March 31,
2003 as compared to the quarter ended March 31, 2002. The
increase in lease operating expense and production taxes is due
to several wells having repairs and maintenance performed, and an
increase in production taxes due to an increase in gross revenues
received during the three months ended March 31, 2003.
Costs and Expenses
Total costs and expenses increased to $47,998 from $45,644 for the
quarters ended March 31, 2003 and 2002, respectively, an increase of
5%. The increase is a direct result of the accretion expense
associated with our long term liability related to expected
abandonment costs of our oil and natural gas properties, depletion
expense 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 less than 1% or approximately $30
during the quarter ended March 31, 2003 as compared to the
quarter ended March 31, 2002.
2. Depletion expense increased to $18,000 for the quarter ended
March 31, 2003 from $17,000 for the same period in 2002. This
represents an increase of 6%. In the fourth quarter of 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. The
effect of this change in method was to increase depletion expense
for the three months ended March 31, 2002 by $5,000 and increase
net income for the three months ended March 31, 2002 by $11,000.
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,
2003, the asset retirement obligation was $67,724, and the increase
in the balance from January 1, 2003 of $1,328 is due to accretion
expense. The pro forma amounts for the three months ended March 31,
2002, which are presented on the face of the statements of
operations, reflect the effect of retroactive application of SFAS No.
143.
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
$179,100 in the quarter ended March 31, 2003 as compared to
approximately $81,900 in the quarter ended March 31, 2002. The
primary source of the 2003 cash flow from operating activities was
profitable operations.
Cash flows used in financing activities were approximately $150,400
in the quarter ended March 31, 2003 as compared to approximately
$149,300 in the quarter ended March 31, 2002. The only use in
financing activities was the distributions to partners.
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.
Total distributions during the quarter ended March 31, 2002 were
$150,000 of which $135,000 was distributed to the limited partners
and $15,000 to the general partners. The per unit distribution to
limited partners during the quarter ended March 31, 2002 was $9.00.
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. The source for the 2002
distributions of $150,000 was oil and gas operations of approximately
$81,900, with the balance from available cash on hand at the
beginning of the period.
Since inception of the Partnership, cumulative monthly cash
distributions of $11,516,053 have been made to the partners. As of
March 31, 2003, $10,379,358 or $691.96 per limited partner unit has
been distributed to the limited partners, representing a 100% return
of the capital and a 38% return on capital contributed.
As of March 31, 2003, the Partnership had approximately $291,700 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.
The Managing General Partner has examined various alternatives to
address the issue of depleting producing reserves. Continuing
operations exposes the partnership to an inevitable decline in
operating results and distributions of cash. Liquidating the
partnership would result in immediate realization of cash for limited
partners, but prices paid by purchasers of Partnership property in
liquidation would likely include a substantial discount for risks and
uncertainties of future cash flows, as well as any development risks.
After reviewing various alternatives, we initiated a plan to merge
the Partnership and 20 other limited partnerships with and into the
Managing General Partner. On October 17, 2002, the Managing General
Partner filed a Registration Statement on form S-4 with the
Securities and Exchange Commission relating to this proposed merger.
There is no assurance, however, that this merger will be consummated.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure
with approximately $124.0 million of principal due between December
31, 2002 and December 31, 2004. The Managing General Partner is
constantly monitoring its cash position and its ability to meet its
financial obligations as they become due, and in this effort, is
continually exploring various strategies for addressing its current
and future liquidity needs. The Managing General Partner regularly
pursues and evaluates recapitalization strategies and acquisition
opportunities (including opportunities to engage in mergers,
consolidations or other business combinations) and at any given time
may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to
fund debt service, developmental projects and day to day operations,
but it is not sufficient to build a cash balance which would allow
the Managing General Partner to meet its debt principal maturities
scheduled for 2004. Therefore the Managing General Partner is
currently seeking to renegotiate the terms of its obligations,
including extending maturity dates, or to engage new lenders or
equity investors in order to satisfy its financial obligations
maturing in 2004.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful. In the event these efforts
are unsuccessful, the Managing General Partner would need to look to
other alternatives to meet its debt obligations, including
potentially selling its assets. There can be no assurance, however,
that the sales of assets can be successfully accomplished on terms
acceptable to the Managing General Partner. Please see the
Partnership's Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2003, which will be filed with the Commission on
or before November 14, 2003, for updated information on the liquidity
of the Managing General Partner. The liquidity of the Managing
General Partner, however, does not have a material impact on the
operations of the Partnership. The partnership agreement of the
Partnership allows the limited partners to elect a successor managing
general partner to continue Partnership operations.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset
Retirement Obligations" which establishes requirements for the
accounting of removal-type costs associated with asset retirements.
The standard is effective for fiscal years beginning after June 15,
2002, with earlier application encouraged. This statement has been
adopted by the Partnership effective January 1, 2003. The transition
adjustment resulting from the adoption of SFAS No. 143 has been
reported as a cumulative effect of a change in accounting principle.
In April 2003, the FASB issued Statement of Financial Accounting
Standards No. 149, Amendment of Statement No. 133 on Derivative
Instruments and Hedging Activities ("SFAS No. 149"). SFAS No. 149
amendments require that contracts with comparable characteristics be
accounted for similarly, clarifies when a contract with an initial
investment meets the characteristic of a derivative and clarifies
when a derivative requires special reporting in the statement of cash
flows. SFAS No. 149 is effective for hedging relationships
designated and for contracts entered into or modified after June 30,
2003, except for provisions that relate to SFAS No. 133 Statement
Implementation Issues that have been effective for fiscal quarters
prior to June 15, 2003, should be applied in accordance with their
respective effective dates and certain provisions relating to forward
purchases or sales of when-issued securities or other securities that
do not yet exist, should be applied to existing contracts as well as
new contracts entered into after June 30, 2003. Assessment by the
Managing General Partner revealed this pronouncement to have no
impact on the partnership.
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
(a) Evaluation of Disclosure Controls and Procedures. The chief
executive officer and chief financial officer of the Partnership's
managing general partner have evaluated the effectiveness of the
design and operation of the Partnership's disclosure controls and
procedures (as defined in Exchange Act Rule 13a-14(c)) as of a date
within 90 days of the filing date of this quarterly report. Based on
that evaluation, the chief executive officer and chief financial
officer have concluded that the Partnership's disclosure controls and
procedures are effective to ensure that material information relating
to the Partnership and the Partnership's consolidated subsidiaries is
made known to such officers by others within these entities,
particularly during the period this quarterly report was prepared, in
order to allow timely decisions regarding required disclosure.
(b) Changes in Internal Controls. There have not been any
significant changes in the Partnership's internal controls or in
other factors that could significantly affect these controls
subsequent to the date of their evaluation.
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:
99.1 Certification pursuant to 18 U.S.C. Section
1350
99.2 Certification pursuant to 18 U.S.C. Section 1350
(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: November 12, 2003
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q/A of
Southwest Royalties Institutional Income Fund VII-B, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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 quarterly report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and we have:
a) designed such disclosure controls and procedures 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 quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, 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 in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data and
have identified for the registrant's auditors any material weaknesses
in internal controls; 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; and
6. The registrant's other certifying officers and I have indicated
in this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our
most recent evaluation, including any corrective actions with regard
to significant deficiencies and material weaknesses.
Date: November 12, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
of Southwest Royalties, Inc., the
Southwest Royalties, Inc., the Managing
General Partner of Southwest Royalties
Institutional Income Fund VII-B, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form 10-Q/A of
Southwest Royalties Institutional Income Fund VII-B, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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 quarterly report;
4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and we have:
a) designed such disclosure controls and procedures 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 quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, 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 in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data and
have identified for the registrant's auditors any material weaknesses
in internal controls; 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; and
6. The registrant's other certifying officers and I have indicated
in this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our
most recent evaluation, including any corrective actions with regard
to significant deficiencies and material weaknesses.
Date: November 12, 2003
/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
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, Limited Partnership (the "Company")
on Form 10-Q/A for the period ending March 31, 2003 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: November 12, 2003
/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
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, Limited Partnership (the "Company")
on Form 10-Q/A for the period ending March 31, 2003 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: November 12, 2003
/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.;