1
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2006
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 0-19601
SOUTWEST ROYALTIES INSTITUTIONAL 1990-91 INCOME PROGRAM
Southwest Royalties Institutional Income Fund X-B, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2332174
(State or other jurisdiction of (I.R.S.
Employer
incorporation or organization)
Identification No.)
6 Desta Drive
Midland, Texas 79705
(Address of principal executive offices)
432-682-6324
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes X No ___
Indicate by check mark whether the registrant is large accelerated filer,
an accelerated filer, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer ___ Accelerated filer ___ Non-
accelerated filer X
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act).
Yes__ No X
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 20.
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.
Bbl. One stock tank barrel, or 42 United States gallons liquid volume.
BOE. Equivalent barrels of oil, with natural gas converted to oil
equivalents based on a ratio of six Mcf of natural gas to one Bbl of oil.
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 natural
gas reserves 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 a leasehold or
working interest agrees to assign his interest in certain specific acreage
to an assignee, retaining some interest, such as an overriding royalty
interest, subject to the drilling of one (1) or more wells or other
specified 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.
Standardized measure of discounted future net cash flows. Present
value of proved reserves, as adjusted to give effect to estimated future
abandonment costs, net of the estimated salvage value of related equipment.
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 oil and gas reserves
that can be expected to be recovered from existing wells with existing
equipment and operating methods.
Proved properties. Properties with proved reserves.
Proved oil and gas reserves. The estimated quantities of crude oil,
natural gas, and natural gas liquids with geological and engineering data
that demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made.
Proved undeveloped reserves. Proved oil and gas 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, 2005, which are found in the Registrant's Form
10-K Report for 2005 filed with the Securities and Exchange Commission.
The December 31, 2005 balance sheet included herein has been taken from the
Registrant's 2005 Form 10-K Report. Operating results for the three and
nine-month periods ended September 30, 2006 are not necessarily indicative
of the results that may be expected for the full year.
Southwest Royalties Institutional Income Fund X-B, L.P.
Balance Sheets
Septembe December
r 30, 31,
2006 2005
----- -----
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 81,016 100,108
Receivable from Managing 124,386 110,738
General Partner
Distribution receivable 45 -
Prepaids 31,759 19,032
-------- --------
---- ----
Total current assets 237,206 229,878
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 3,919,30 3,948,41
0 8
Less accumulated
depreciation,
depletion and 3,647,05 3,634,59
amortization 9 7
-------- --------
---- ----
Net oil and gas 272,241 313,821
properties
-------- --------
---- ----
$ 509,447 543,699
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ----
Asset retirement obligation $ 221,575 238,110
-------- --------
---- ----
Partners' equity (deficit):
General partners (45,709) (44,281)
Limited partners 333,581 349,870
-------- --------
---- ----
Total partners' equity 287,872 305,589
-------- --------
---- ----
$ 509,447 543,699
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund X-B, L.P.
Statements of Operations
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2006 2005 2006 2005
----- ----- ----- -----
Revenues
- ------------
Income from net profits $ 224,805 254,322 783,900 638,422
interests
Interest 1,142 403 2,932 965
Other - - 40 -
-------- --------- -------- --------
-- - -- --
225,947 254,725 786,872 639,387
-------- --------- -------- --------
-- - -- --
Expenses
- ------------
Depreciation, depletion and 3,994 4,503 12,462 13,226
amortization
Accretion of asset 4,609 2,367 13,562 7,097
retirement obligation
General and administrative 23,052 20,418 73,144 64,780
-------- --------- -------- --------
-- - -- --
31,655 27,288 99,168 85,103
-------- --------- -------- --------
-- - -- --
Net income $ 194,292 227,437 687,704 554,284
====== ====== ====== ======
Net income allocated to:
Managing General Partner $ 17,846 20,875 63,015 51,076
====== ====== ====== ======
General Partner $ 1,983 2,319 7,002 5,675
====== ====== ====== ======
Limited Partners $ 174,463 204,243 617,687 497,533
====== ====== ====== ======
Per limited partner $ 15.60 18.27 55.24 44.50
unit
====== ====== ====== ======
The accompanying notes are an integral
part of these financial statements.
<PAGE
Southwest Royalties Institutional Income Fund X-B, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
2006 2005
----- -----
Cash flows from operating activities
Cash received from income from net
profits interests $ 756,546 635,524
Cash paid to suppliers (73,144 (64,780)
)
Interest received 2,932 965
Other 40 -
------- --------
--- --
Net cash provided by operating 686,374 571,709
activities
------- --------
--- --
Cash flows from financing activities
Distributions to partners (705,42 (550,000
1) )
(Decrease) increase in distributions (45) 1,610
payable
------- --------
--- --
Net cash used in financing (705,46 (548,390
activities 6) )
------- --------
--- --
Net (decrease) increase in cash and (19,092 23,319
cash equivalents )
Beginning of period 100,108 73,836
------- --------
--- --
End of period $ 81,016 97,155
====== ======
Reconciliation of net income to net
cash
provided by operating activities
Net income $ 687,704 554,284
Adjustments to reconcile net income
to net
cash provided by operating
activities
Depreciation, depletion and 12,462 13,226
amortization
Accretion of asset retirement 13,562 7,097
obligation
Settlement of asset retirement
obligations
for plugged and abandoned wells (979) (3,083)
(Increase) decrease in receivables (26,375 185
)
------- --------
--- --
Net cash provided by operating $ 686,374 571,709
activities
====== ======
Noncash investing and financing
activities:
Decrease in oil and gas properties - $ (29,118 -
SFAS No. 143 )
====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund X-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund X-B, L.P. was organized
under the laws of the state of Delaware on November 27, 1990 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. a wholly owned subsidiary of Clayton Williams Energy, Inc.,
serves as the Managing General Partner and Blue Heel Company, a wholly
owned subsidiary of Southwest Royalties, Inc., acquired the general
partner interest from H.H. Wommack, III. Revenues, costs and expenses
are allocated as follows:
Limited General
Partners Partners
-------- --------
Interest income on 100% -
capital contributions
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and 100% -
offering costs (1)
Amortization of 100% -
organization costs
Property acquisition 100% -
costs
Gain/loss on property 90% 10%
disposition
Operating and 90% 10%
administrative costs
(2)
Depreciation, depletion
and amortization
of oil and gas 100% -
properties
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 September 30, 2006, and for
the three and nine months ended September 30, 2006, is unaudited.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim
financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments
are of a normal recurring nature. The interim consolidated financial
statements should be read in conjunction with the Partnership's Annual
Report on Form 10-K for the year ended December 31, 2005.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC
staff's views regarding SFAS No. 143 and its impact on both the full-
cost ceiling test and the calculation of depletion expense. In
accordance with SAB 106, beginning in the first quarter of 2005,
undiscounted abandonment costs for wells to be drilled in the future
to develop proved reserves are included in the unamortized cost of oil
and gas properties, net of related salvage value, for purposes of
computing depreciation, depletion and amortization ("DD&A"). The
implementation of SAB 106 did not have a material impact on our
financial statements.
Southwest Royalties Institutional Income Fund X-B, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
3. Asset Retirement Obligations
Changes in abandonment obligations for the nine months ended September
30, 2006 and 2005 are as follows:
2006 2005
------- -------
Beginning of period $ 238,110 217,668
Reduction of obligations due to (29,118 -
farmouts )
Settlement of obligations for (979) (3,083)
plugged and abandoned wells
Accretion expense 13,562 7,097
------- -------
------- -----
End of period $ 221,575 221,682
======= =======
=
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund X-B, L.P. was organized as a
Delaware limited partnership on November 27, 1990. The offering of such
limited partnership interests began December 1, 1990 as part of a shelf
offering registered under the name Southwest Royalties Institutional 1990-
91 Income Program. Minimum capital requirements for the Partnership were
met on March 11, 1991, with the offering of limited partnership interests
concluding September 30, 1991, with total limited partner contributions of
$5,590,500.
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 farmout 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.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
sold.
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 September 30, 2006, 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
September 30, 2006, there were no timing differences, which resulted in a
deficit net profit interest.
Critical Accounting Policies
The Partnership follows the full cost method of accounting for its oil and
gas properties. The full cost method subjects companies to quarterly
calculations of a "ceiling", or limitation on the amount of properties that
can be capitalized on the balance sheet. If the Partnership's capitalized
costs are in excess of the calculated ceiling, the excess must be written
off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants.
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 depletion, depreciation, and amortization
("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.
Supplemental Information
The following unaudited information is intended to supplement the financial
statements included in this Form 10-Q with data that is not readily
available from those statements.
Three Months Ended
September 30,
2006 2005
------ ------
Oil production in 4,228 4,740
barrels
Gas production in mcf 11,529 16,800
Total (BOE) 6,150 7,540
Average price per barrel $ 67.69
of oil 60.97
Average price per mcf of $ 7.75
gas 7.54
Partnership $ 225,000 175,000
distributions
Limited partner $ 202,500 157,500
distributions
Per unit distribution to $ 18.11
limited partners 14.09
Number of limited 11,181 11,181
partner units
Operating Results
The following discussion compares our results for the quarters ended
September 30, 2006 and 2005. Unless otherwise indicated, references to
2006 and 2005 within this section refer to the respective quarterly period.
Income from net profits
Oil and gas prices continued to climb to record levels compared to the
previous two years. Comparing 2006 to 2005, oil and gas sales decreased
$40,100, of which price variances accounted for a $30,800 increase and
production variances accounted for a $70,900 decrease.
Production in 2006 (on a BOE basis) was 18% lower than 2005. Our oil
production was 11% lower in 2006 than 2005 due primarily to the production
decline on one property. Also contributing to the decline is lower volumes
from a property that now has a reduced revenue interest as a result of a
farmout for development of the property. Our gas production was 31% lower
in 2006 than 2005 due primarily to a sharp production decline on a gas
well. Also contributing to the decline is lower volumes from three
properties that now have a reduced revenue interest as a result of a
farmout for development of these properties.
In 2006, our realized oil price was 11% higher than 2005, while our
realized gas price was 3% higher. Historically, the markets for oil and
gas have been volatile, and they are likely to continue to be volatile. We
have very little control over the prices we receive for our production at
the wellhead since most of our physical marketing arrangements are market-
sensitive.
Oil and gas production costs on a BOE basis increased from $21.39 per BOE
in 2005 to $24.51 per BOE in 2006. This increase was the result of oil and
gas production cost decrease of 7% while the volume reduction was 18%.
Expenses
Depletion on a BOE basis increased 9% in 2006. Comparing 2006 to 2005,
depletion expense decreased $500, of which rate variances accounted for a
$300 increase and production variances accounted for a $800 decrease.
Accretion expense increased 95% in 2006 due primarily to fourth quarter
2005 revisions in previous estimates related to increased costs to plug
wells.
General and administrative ("G&A") expenses were 13% higher in 2006 as
compared to 2005. The increase in general and administrative expenses is
primarily due to higher professional fees for audit, tax and engineering
services.
Supplemental Information
The following unaudited information is intended to supplement the financial
statements included in this Form 10-Q with data that is not readily
available from those statements.
Nine Months Ended
September 30,
2006 2005
------ ------
Oil production in 14,182 14,162
barrels
Gas production in mcf 40,389 49,666
Total (BOE) 20,914 22,440
Average price per barrel $ 66.21
of oil 53.50
Average price per mcf of $ 6.72
gas 6.38
Partnership $ 705,421 550,000
distributions
Limited partner $ 633,976 495,000
distributions
Per unit distribution to $ 56.70
limited partners 44.27
Number of limited 11,181 11,181
partner units
Operating Results
The following discussion compares our results for the nine months ended
September 30, 2006 and 2005. Unless otherwise indicated, references to
2006 and 2005 within this section refer to the respective nine-month
period.
Income from net profits
Oil and gas prices continued to climb to record levels compared to the
previous two years. Comparing 2006 to 2005, oil and gas sales increased
$136,000, of which price variances accounted for a $194,100 increase and
production variances accounted for a $58,100 decrease.
Production in 2006 (on a BOE basis) was 7% lower than 2005. We increased
our oil production in 2006 by less than 1%. Our gas production was 19%
lower in 2006 than 2005 due primarily to a sharp production decline on a
gas well. Also contributing to the decline is lower volumes from three
properties that now have a reduced revenue interest as a result of a
farmout for development of these properties.
In 2006, our realized oil price was 24% higher than 2005, while our
realized gas price was 5% higher. Historically, the markets for oil and
gas have been volatile, and they are likely to continue to be volatile. We
have very little control over the prices we receive for our production at
the wellhead since most of our physical marketing arrangements are market-
sensitive.
Oil and gas production costs on a BOE basis increased from $19.43 per BOE
in 2005 to $20.40 per BOE in 2006.
Expenses
Depletion on a BOE basis increased 1% in 2006. Comparing 2006 to 2005,
depletion expense decreased $800, of which rate variances accounted for a
$100 increase and production variances accounted for a $900 decrease.
Accretion expense increased 91% in 2006 due primarily to fourth quarter
2005 revisions in previous estimates related to increased costs to plug
wells.
General and administrative ("G&A") expenses were 13% higher in 2006 as
compared to 2005. The increase in general and administrative expenses is
primarily due to higher professional fees for audit, tax and engineering
services.
Liquidity and Capital Resources
Partnership distributions during the nine months ended September 30, 2006
were $705,421, of which $633,976 was distributed to the limited partners
and $71,445 to the general partners. Cumulative cash distributions of
$7,648,444 have been made to the general and limited partners as of
September 30, 2006. As of September 30, 2006, $6,942,588 or $620.93 per
limited partner unit has been distributed to the limited partners,
representing 124% of contributed capital.
Texas Margin Taxes
In May 2006, the State of Texas adopted House Bill 3, which modified the
state's franchise tax structure, replacing the previous tax based on
capital or earned surplus with a margin tax (the "Texas Margin Tax")
effective with franchise tax reports filed on or after January 1, 2008. The
Texas margin Tax is computed by applying the applicable tax rate (1% for
the Partnership's business) to the profit margin, which is generally
determined by total revenue less either cost of goods sold or compensation
as applicable. However the Partnership believes, based on it's
interpretation, that the Texas Margin Tax does not apply to the Partnership
since substantially all of it's income is derived from a net profits
interest.
Recent Accounting Pronouncements
There were no recent accounting pronouncements that had a significant
effect 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
The Managing General Partner has established disclosure controls and
procedures that are adequate to provide reasonable assurance that
management will be able to collect, process and disclose both financial and
non-financial information, on a timely basis, in the Partnership's reports
to the SEC. Disclosure controls and procedures include all processes
necessary to ensure that material information is recorded, processed,
summarized and reported within the time periods specified in the SEC's
rules and forms, and is accumulated and communicated to management,
including our chief executive and chief financial officers, to allow timely
decisions regarding required disclosures.
With respect to these disclosure controls and procedures:
management has evaluated the effectiveness of the disclosure
controls and procedures as of the end of the period covered by
this report;
this evaluation was conducted under the supervision and with the
participation of management, including the chief executive and
chief financial officers of the Managing General Partner; and
it is the conclusion of chief executive and chief financial
officers of the Managing General Partner that these disclosure
controls and procedures are effective in ensuring that
information that is required to be disclosed by the Partnership
in reports filed or submitted with the SEC is recorded,
processed, summarized and reported within the time periods
specified in the rules and forms established by the SEC.
Internal Control Over Financial Reporting
There has not been any change in the Partnership's internal control over
financial reporting that occurred during the nine months ended September
30, 2006 that has materially affected, or is reasonably likely to
materially affect, its internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Certification of Chief Executive Officer
and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 X-B, L.P., a Delaware limited partnership
By: Southwest Royalties, Inc.,
Managing
General Partner
By: /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
Date: November 13, 2006
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties Institutional Income Fund X-B, L.P.
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: November 13, 2006 /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income
Fund X-B, L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties Institutional Income Fund X-B, L.P.
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: November 13, 2006 /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income
Fund X-B, L.P.
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND
CHIEF FINANCIAL OFFICER
Pursuant to 18 U.S.C. 1350 and in connection with the accompanying report
on Form 10-Q for the period ended September 30, 2006 that is being filed
concurrently with the Securities and Exchange Commission on the date hereof
(the "Report"), each of the undersigned officers of Southwest Royalties
Institutional Income Fund X-B, L.P. (the "Company"), hereby certifies 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.
/s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund X-B, L.P.
November 13, 2006
/s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional
Income Fund X-B, L.P.
November 13, 2006