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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 0-18398
Southwest Royalties Institutional Income Fund IX-B, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2274633
(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 IX-B, L.P.
Balance Sheets
March December
31, 31,
2003 2002
(Restate
d)
------ ------
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 71,095 51,870
Receivable from Managing 133,235 83,392
General Partner
-------- --------
---- ----
Total current assets 204,330 135,262
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 3,012,07 2,952,22
0 2
Less accumulated
depreciation,
depletion and 2,634,02 2,720,00
amortization 1 0
-------- --------
---- ----
Net oil and gas properties 378,049 232,222
-------- --------
---- ----
$ 582,379 367,484
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability - $ 74 161
distribution payable
-------- --------
---- ----
Other long term liabilities 166,946 -
-------- --------
---- ----
Partners' equity:
General partners (56,945) (62,349)
Limited partners 472,304 429,672
-------- --------
---- ----
Total partners' equity 415,359 367,323
-------- --------
---- ----
$ 582,379 367,484
======= =======
Southwest Royalties Institutional Income Fund IX-B, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2003 2002
(Restate (Restate
d) d)
----- -----
Revenues
- --------
Income from net profits $ 167,555 56,905
interests
Interest 124 143
-------- --------
-- -
167,679 57,048
-------- --------
-- -
Expenses
- --------
General and administrative 18,525 18,400
Depreciation, depletion and 6,000 6,000
amortization
Accretion 3,273 -
-------- --------
-- -
27,798 24,400
-------- --------
-- -
Net income before cumulative 139,881 32,648
effect
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See (11,845) -
Note 3
Cumulative effect of change in
accounting principle
- change in depletion method - - (31,000)
See Note 4
-------- --------
-- -
Net income $ 128,036 1,648
====== =====
Net income (loss) allocated to:
Managing General Partner $ 12,064 3,479
====== =====
General partner $ 1,340 386
====== =====
Limited partners $ 114,632 (2,217)
====== =====
Per limited partner unit $ 12.81 2.94
before cumulative effect
Cumulative effects per (1.09)
limited partner unit (3.17)
-------- --------
-- -
Per limited partner unit $ 11.72 (.23)
====== =====
Pro forma amounts assuming
changes are applied
retroactively (See Note 3):
Net income before cumulative $ - 29,636
effect
====== =====
Per limited partner unit $ - 2.66
(9,782.0)
====== =====
Net income (loss) $ - (1,364)
====== =====
Per limited partner unit $ - (.51)
(9,782.0)
====== =====
Southwest Royalties Institutional Income Fund IX-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
net profits
interests $ 108,486 63,954
Cash paid to suppliers (9,298) (21,325)
Interest received 124 143
-------- --------
-- -
Net cash provided by operating 99,312 42,772
activities
-------- --------
-- -
Cash flows used in financing
activities:
Distributions to partners (80,086) (50,085)
-------- --------
-- -
Net increase (decrease) in cash 19,225 (7,313)
and cash equivalents
Beginning of period 51,870 28,023
-------- --------
-- -
End of period $ 71,095 20,710
====== =====
Reconciliation of net income to
net
cash provided by operating
activities:
Net income $ 128,036 1,648
Adjustments to reconcile net
income to
net cash provided by operating
activities:
Depreciation, depletion and 6,000 6,000
amortization
Accretion 3,273 -
Cumulative effect of change in
accounting
principle - SFAS No. 143 11,845 -
Cumulative effect of change in
accounting
principle - change in depletion - 31,000
method
(Increase) decrease in (59,069) 7,049
receivables
Increase (decrease) in payables 9,227 (2,925)
-------- --------
-- -
Net cash provided by operating $ 99,312 42,772
activities
====== =====
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption
of SFAS No.143 $ 151,827 -
====== ======
Southwest Royalties Institutional Income Fund IX-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund IX-B, L.P. was organized
under the laws of the state of Delaware on March 9, 1989, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership sells its oil and
gas production to a variety of purchasers with the prices it receives
being dependent upon the oil and gas economy. Southwest Royalties,
Inc. serves as the Managing General Partner and H. H. Wommack, III, as
the individual general partner. Revenues, costs and expenses are
allocated as follows:
Limited General
Partners Partners
-------- --------
Oil and gas sales 90% 10%
Interest income on capital 100% -
contributions
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 100% -
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 IX-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 $151,827, a long term liability of
approximately $163,672 and a loss of approximately $11,845 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 $166,946, and the increase
in the balance from January 1, 2003 of $3,273 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 $31,000 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 $2,000 ($.20 per limited partner unit) and net income by
$33,000 ($3.37 per limited partner unit).
Southwest Royalties Institutional Income Fund IX-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 $209,370 from $376,316 to $166,946 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 $3,273 7,379
Income before cumulative effect 139,881 135,775
Cumulative effect of change in (11,845) (266,252)
accounting principle
Net income (loss) 128,036 (130,477)
Net income (loss) allocated
to:
Managing General Partner 12,064 (8,566)
General partner 1,340 (952)
Limited partners 114,632 (120,959)
Income (loss) per limited
partner unit before
cumulative effect 12.81 (12.37)
Cumulative effect per (1.09) -
limited partner unit
Net income (loss) per 11.72 (12.37)
limited partner unit
Southwest Royalties Institutional Income Fund IX-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 a decrease
in the Partnership's previously reported net oil and gas properties of
$32,000 from $264,222 to $232,222 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 $6,000 4,000
amortization
Income before cumulative effect 32,648 34,648
Cumulative effect of change in (31,000) -
accounting principle
Net income 1,648 34,648
Net income (loss) allocated
to:
Managing General Partner 3,479 3,479
General partner 386 386
Limited partners (2,217) 30,783
Income per limited partner
unit before
cumulative effect 2.94 3.15
Cumulative effect per (3.17) -
limited partner unit
Net income (loss) per (.23) 3.15
limited partner unit
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund IX-B, L.P. was organized as a
Delaware limited partnership on March 9, 1989. The offering of such limited
partnership interests began on May 11, 1989, minimum capital requirements
were met on September 26, 1989, and the offering concluded on March 31,
1990, with total limited partner contributions of $4,891,000.
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 are not 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 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 8% 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 $2,000 and
decrease net income for the three months ended March 31, 2002 by $33,000.
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 $2,000 and
decrease net income for the three months ended March 31, 2002 by $33,000.
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 $ 32.47 68%
barrel of oil 19.32
Average price per mcf $ 5.22 202%
of gas 1.73
Oil production in 4,200 4,700 (11%)
barrels
Gas production in mcf 21,100 25,800 (18%)
Income from net profits $ 167,555 56,905 194%
interests
Partnership $ 80,000 50,000 60%
distributions
Limited partner $ 72,000 45,000 60%
distributions
Per unit distribution
to limited
partners $ 7.36 60%
4.60
Number of limited 9,782 9,782
partner units
Revenues
The Partnership's income from net profits interests increased to $167,555
from $56,905 for the quarters ended March 31, 2003 and 2002, respectively,
an increase of 194%. 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 68%, or $13.15 per barrel, resulting in
an increase of approximately $55,200 in income from net profits
interests. Oil sales represented 55% of total oil and gas sales during
the quarter ended March 31, 2003 as compared to 67% 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 202%, or $3.49 per mcf, resulting
in an increase of approximately $73,600 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
$128,800. 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 500 barrels or 11% during the
same period, resulting in a decrease of approximately $9,700 in income
from net profits interests.
Gas production decreased approximately 4,700 mcf or 18% during the same
period, resulting in a decrease of approximately $8,100 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $17,800. The decrease in gas
production is primarily due to a property sale during November 2002,
which produced approximately 4,500 mcf during the quarter ended March
31, 2002.
3. Lease operating costs and production taxes were 1% higher, or
approximately $400 more during the quarter ended March 31, 2003 as
compared to the quarter ended March 31, 2002.
Costs and Expenses
Total costs and expenses increased to $27,798 from $24,400 for the quarters
ended March 31, 2003 and 2002, respectively, an increase of 14%. 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 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 1%
or approximately $100 during the quarter ended March 31, 2003 as
compared to the quarter ended March 31, 2002.
2. Depletion expense remained unchanged for the quarter ended March 31,
2003 as compared to the same period in 2002. 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
$2,000 and decrease net income for the three months ended March 31,
2002 by $33,000.
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 $151,827, a long term liability of
approximately $163,672 and a loss of approximately $11,845 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 $166,946, and the increase in the balance from
January 1, 2003 of $3,273 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 $99,300 in
the quarter ended March 31, 2003 as compared to approximately $42,800 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 $80,100 in the
quarter ended March 31, 2003 as compared to approximately $50,100 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, 2003 were $80,000 of
which $72,000 was distributed to the limited partners and $8,000 to the
general partners. The per unit distribution to limited partners during the
quarter ended March 31, 2003 was $7.36. Total distributions during the
quarter ended March 31, 2002 were $50,000 of which $45,000 was distributed
to the limited partners and $5,000 to the general partners. The per unit
distribution to limited partners during the quarter ended March 31, 2002
was $4.60.
The source for the 2003 distributions of $80,000 was oil and gas operations
of approximately $99,300, resulting in excess cash for contingencies or
subsequent distributions. The source for the 2002 distributions of $50,000
was oil and gas operations of approximately $42,800, with the balance from
available cash on hand at the beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $7,205,286 have been made to the partners. As of March 31, 2003,
$6,540,018 or $668.58 per limited partner unit has been distributed to the
limited partners, representing a 100% return of the capital and 34% return
on capital contributed.
As of March 31, 2003, the Partnership had approximately $204,300 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. The Managing General Partner is currently assessing the impact
on the partnerships financial statements. 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 IX-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 IX-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 Managing
General Partner of Southwest Royalties
Institutional Income Fund IX-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 IX-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 IX-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 IX-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 IX-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 IX-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 IX-B, L.P.