SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B LP - FORM 10-Q

Attached files

file	filename
EX-31.2 - CERTIFICATION OF CFO - SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B LP	mel9300931_2217.htm
EX-31.1 - CERTIFICATION OF CEO - SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B LP	paul9300931_1217.htm
EX-32.1 - CERTFICATION OF CEO &AMP; CFO - SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B LP	paulmel9300932_1217.htm

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, 2009

¨ 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	(I.R.S. Employer
of incorporation or organization)	Identification No.)

6 Desta Drive, Suite 6500, Midland, Texas	79705
(Address of principal executive office)	(Zip Code)

(432) 682-6324

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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:YesxNo¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
¨ Yes	¨ No

Indicate by check mark whether the registrant is a 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.
Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer x		Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
¨ Yes	x No

	Table of Contents

		Page
	Glossary	3

	Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements	5

	Balance Sheets as of September 30, 2009 and December 31, 2008	6

	Statements of Operations for the three months and nine months ended September 30, 2009 and 2008	7

	Statements of Cash flows for the nine months ended September 30, 2009 and 2008	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	16

Item 4.	Controls and Procedures	16


	Part II – OTHER INFORMATION

Item 1.	Legal Proceedings	17

Item 1A.	Risk Factors	17

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	18

Item 3.	Defaults Upon Senior Securities	18

Item 4.	Submission of Matter to a Vote of Security Holders	18

Item 5.	Other Information	18

Item 6.	Exhibits	18

	Signatures	19

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.

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 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 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 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.

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.

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.

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, 2008, which are found in the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission. The December 31, 2008 balance sheet included herein has been taken from the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008. Operating results for the three and nine month periods ended September 30, 2009 are not necessarily indicative of the results that may be expected for the full year.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Balance Sheets

	September 30,			December 31,
	2009			2008
	(unaudited)
Assets

Current assets:
Cash and cash equivalents	$	37,991		$	45,290
Receivable from Managing General Partner		12,376			37,449
New Mexico income tax deposits		30,199			25,554
Total current assets		80,566			108,293

Oil and gas properties - using the full-
cost method of accounting		3,189,866			3,189,361
Less accumulated depreciation,
depletion and amortization		2,788,193			2,758,343
Net oil and gas properties		401,673			431,018

	$	482,239		$	539,311
Liabilities and Partners' Equity (Deficit)

Asset retirement obligation	$	495,548		$	424,384

Partners' equity (deficit):
General partners		(86,038	)		(75,903	)
Limited partners		72,729			190,830

Total partners' (deficit) equity		(13,309	)		114,927

	$	482,239		$	539,311

The accompanying notes are an integral

part of these financial statements.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Statements of Operations

(unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Revenues

Income from net profits interests	$	68,181	$	219,175	$	203,815	$	797,002
Interest		20		186		64		450
		68,201		219,361		203,879		797,452

Expenses

Depreciation, depletion and amortization		8,837		7,699		29,850		24,836
Accretion expense		10,584		9,280		29,897		19,570
General and administrative		25,106		22,385		77,504		75,557
		44,527		39,364		137,251		119,963

Net income	$	23,674	$	179,997	$	66,628	$	677,489

Net income allocated to:

Managing General Partner	$	2,926	$	16,893	$	8,683	$	63,210

General Partner	$	325	$	1,877	$	965	$	7,023

Limited partners	$	20,423	$	161,227	$	56,980	$	607,256

Per limited partner unit	$	2.09	$	16.48	$	5.83	$	62.08

The accompanying notes are an integral

part of these financial statements.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Statements of Cash Flows

(unaudited)

	Nine Months Ended
	September 30,
	2009			2008
Cash flows from operating activities:

Cash received from income from net profits
interests	$	224,243		$	667,905
Cash paid to suppliers		(77,504	)		(81,617	)
Interest received		64			450
Net cash provided by operating activities		146,803			586,738

Cash flows provided by investing activities:

Proceeds from oil and gas properties		40,762			-

Cash flows used in financing activities:

Distributions to partners		(194,864	)		(580,648	)

Net (decrease) increase in cash and cash equivalents		(7,299	)		6,090

Beginning of period		45,290			50,934

End of period	$	37,991		$	57,024

Reconciliation of net income to net cash
provided by operating activities:

Net income	$	66,628		$	677,489

Adjustments to reconcile net income to net
cash provided by operating activities:

Depreciation, depletion and amortization		29,850			24,836
Accretion expense		29,897			19,570
Decrease (increase) in receivables		20,428			(129,097	)
Decrease in payables		-			(6,060	)

Net cash provided by operating activities	$	146,803		$	586,738

Noncash investing and financing activities:

Increase in oil and gas
properties – Asset retirement obligations	$	41,267		$	12,290

The accompanying notes are an integral

part of these financial statements.

Southwest Royalties Institutional Income Fund IX-B, L.P.

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., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as the Managing General Partner.

Revenues, costs and expenses are allocated as follows:

	Limited	General
	Partners	Partners
Oil and gas sales	90%	10%
Interest income on capital contributions	100%	-
All other revenues	90%	10%
Organization and offering costs (1)	100%	-
Syndication costs	100%	-
Amortization of organization costs	100%	-
Property acquisition costs	100%	-
Gain/loss on property disposition	90%	10%
Operating and administrative costs (2)	90%	10%
Depreciation, depletion and amortization of oil and gas properties	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 September 30, 2009, and for the three and nine months ended September 30, 2009, 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, 2008.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Notes to Financial Statements

3. Abandonment Obligations

The Partnership follows the provisions of ASC topic 410-20, formerly SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). ASC topic 410-20 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 capitalize an equal amount as a cost of the asset. The cost associated with the abandonment obligations, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

Changes in abandonment obligations for the nine months ended September 30, 2009 and 2008 are as follows:

	2009			2008
Beginning of period	$	424,384		$	389,539
Reduction of obligations due to farm-out		(468	)		(201	)
Additional abandonment obligations from new wells		-			99
Revisions of estimates		41,735			12,392
Accretion expense		29,897			19,570
End of period	$	495,548		$	421,399

4. Recent Accounting Pronouncements

Effective July 1, 2009, the Partnership adopted SFAS No. 168, “The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards Codification (“ASC”). SFAS 168 establishes the ASC as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Other than the manner in which new accounting guidance is referenced, the adoption did not have a material impact on our financial statements.

Effective April 1, 2009, the Partnership adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”) (superseded by ASC topic 855-10-5), which establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of SFAS 165 did not have a material impact on our disclosure of subsequent events.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or results of operations.

5. Subsequent Events

The Partnership has evaluated events and transactions that occurred after the balance sheet date of September 30, 2009 through November 16, 2009, the date the financial statements were available to be issued. The Partnership did not have any subsequent events that would require recognition in the financial statements or disclosures in these notes to the financial statements.

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 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, increases and decreases in production costs, 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.

Production costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately to production volumes ore revenue. Net income available for distribution to the partners is therefore expected to decline in later years based on these factors.

Oil and Gas Properties

The Partnership uses the full cost method of accounting for its oil and gas producing activities. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves are capitalized. Depletion is provided using the unit-of production method based upon estimates of proved oil and gas reserves. The amortizable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage value. All of the Partnership’s oil and gas properties are located within the United States. 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, 2009, 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, 2009, 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”).

Oil and gas prices have a significant impact on the discounted present value of the Partnership’s estimated proved oil and gas reserves. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. As a result, the changes in oil and gas prices have a significant impact on the computation of the ceiling calculation.

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,
	2009		2008
Oil production in barrels		1,963		2,160
Gas production in mcf		8,222		9,098
Total (BOE)		3,333		3,676
Average price per barrel of oil	$	64.11	$	113.67
Average price per mcf of gas	$	4.30	$	10.14
Partnership distributions	$	55,000	$	290,000
Limited partner distributions	$	49,500	$	261,000
Per unit distribution to limited partners	$	5.06	$	26.68
Number of limited partner units		9,782		9,782

Operating Results

The following discussion compares our results for the quarters ended September 30, 2009 and 2008. Unless otherwise indicated, references to 2009 and 2008 within this section refer to the respective quarterly period.

Revenue

Comparing 2009 to 2008, oil and gas sales decreased $176,548, of which price variances accounted for a $145,273 decrease and production variances accounted for a $31,275 decrease.

Production in 2009 (on a BOE basis) was 9% lower than 2008. Our oil production decreased 9% in 2009. Our gas production was 10% lower in 2009 than 2008 due primarily to the production decline on one property.

In 2009, our realized oil price was 44% lower than 2008, while our realized gas price was 58% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on a BOE basis decreased from $32.26 per BOE in 2008 to $27.91 per BOE in 2009. The lower oil and gas production costs in 2009 were due primarily to subsurface repairs on an oil well in 2008.

Expenses

Depletion on a BOE basis increased 27% in 2009. Comparing 2009 to 2008, depletion expense increased $1,138, of which rate variances accounted for a $1,856 increase and production variances accounted for a $718 decrease.

Accretion expense increased 14% in 2009 due primarily to changes in asset retirement obligations.

General and administrative (“G&A”) expenses were 12% higher in 2009 due primarily to increases in professional fees.

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,
	2009		2008
Oil production in barrels		6,694		8,266
Gas production in mcf		23,373		24,389
Total (BOE)		10,590		12,331
Average price per barrel of oil	$	51.64	$	111.51
Average price per mcf of gas	$	3.77	$	10.28
Partnership distributions	$	194,864	$	580,648
Limited partner distributions	$	175,081	$	522,462
Per unit distribution to limited partners	$	17.90	$	53.41
Number of limited partner units		9,782		9,782

Operating Results

The following discussion compares our results for the nine months ended September 30, 2009 and 2008. Unless otherwise indicated, references to 2009 and 2008 within this section refer to the respective nine month period.

Revenue

Comparing 2009 to 2008, oil and gas sales decreased $738,544, of which price variances accounted for a $552,815 decrease and production variances accounted for a $185,729 decrease.

Production in 2009 (on a BOE basis) was 14% lower than 2008. Our oil production decreased 19% in 2009 due primarily to production declines on two oil wells. Our gas production was 4% lower in 2009 than 2008.

In 2009, our realized oil price was 54% lower than 2008, while our realized gas price was 63% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on a BOE basis decreased from $30.44 per BOE in 2008 to $21.72 per BOE in 2009. The decrease in oil and gas production costs in 2009 was due primarily to surface and subsurface repairs to an oil well in 2008 and subsurface repairs to a gas well in 2008.

Expenses

Depletion on a BOE basis increased 40% in 2009. Comparing 2009 to 2008, depletion expense increased $5,014, of which rate variances accounted for a $8,521 increase and production variances accounted for a $3,507 decrease.

Accretion expense increased 53% in 2009 due primarily to changes in asset retirement obligations.

General and administrative (“G&A”) expenses were 3% higher in 2009 due primarily to increases in professional fees.

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. The Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership since substantially all of its income is derived from a net profits interest.

Liquidity and Capital Resources

Partnership distributions during the nine months ended September 30, 2009 were $194,864, of which $175,081 was distributed to the limited partners and $19,783 to the general partners. Cumulative cash distributions of $10,445,606 have been made to the general and limited partners as of September 30, 2009. As of September 30, 2009, $9,454,662 or $966.54 per limited partner unit has been distributed to the limited partners, representing 193% of contributed capital.

Recent Accounting Pronouncements

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, trading activities in commodities future markets, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. The Partnership cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our financial condition, results of operations and cash distributions to partners.

The Partnership is not a party to any derivative or embedded derivative instruments.

Item 4. Controls and Procedures

Disclosure 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, 2009 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 1A. Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the U.S. Securities and Exchange Commission on March 27, 2009 and available at www.sec.gov. Following are additional risk factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

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

(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
	IX-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 16, 2009

Attached files

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B LP Reports

Also read