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, 2011

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 33-11576

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

(Exact name of registrant as specified in
its limited partnership agreement)

Delaware		75-2165825
(State or other jurisdiction		(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: Yes x No ¨

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). x 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

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.

Table of Contents

Table of Contents

		Page
	Glossary	3

Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements	5

	Balance Sheets as of September 30, 2011 and December 31, 2010	6

	Statements of Operations for the three months and nine months ended September 30, 2011 and 2010	7

	Statements of Cash flows for the nine months ended September 30, 2011 and 2010	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	15

Item 4.	Controls and Procedures	15

Part II – OTHER INFORMATION

Item 1.	Legal Proceedings	16

Item 1A.	Risk Factors	16

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	16

Item 3.	Defaults Upon Senior Securities	16

Item 4.	(Removed and Reserved)	16

Item 5.	Other Information	16

Item 6.	Exhibits	16

	Signatures	17

Table of Contents

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 exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One barrel, or 42 U.S. gallons of liquid volume.

BOE. Means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

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.

Completion . The installation of permanent equipment for the production of oil or gas.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another 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.

Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

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 of proved reserves (“PV-10”). The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

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 (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Table of Contents

Proved properties. Properties with proved reserves.

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.

Proved undeveloped reserves. Undeveloped oil and gas reserves are reserves of any category 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. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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 gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover. Operations on a producing well to restore or increase production.

Table of Contents

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, 2010, which are found in the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission. The December 31, 2010 balance sheet included herein has been taken from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010. Operating results for the three and nine month periods ended September 30, 2011 are not necessarily indicative of the results that may be expected for the full year.

Table of Contents

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

Balance Sheets

	September 30,			December 31,
	2011			2010
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	196,505		$	121,184
Receivable from Managing General Partner	128,315			192,927
State income tax deposits	3,591			3,841
Total current assets	328,411			317,952

Oil and gas properties - using the full-cost method of accounting	4,306,226			4,306,226
Less accumulated depreciation, depletion and amortization	3,922,177			3,897,050

Net oil and gas properties	384,049			409,176
	$	712,460		$	727,128

Liabilities and Partners’ Equity (Deficit)

Asset retirement obligation	$	178,341		$	211,782

Partners’ equity (deficit):
General partner	(585,085		)	(586,777		)
Limited partners	1,119,204			1,102,123

Total partners’ equity	534,119			515,346
	$	712,460		$	727,128

The accompanying notes are an integral
part of these financial statements.

Table of Contents

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

Statements of Operations

(unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Revenues

Income from net profits interests	$	270,666	$	257,423	$	754,328	$	744,734
Interest	106		76		367		253
	270,772		257,499		754,695		744,987

Expenses

Depreciation, depletion and amortization	7,748		8,476		25,127		27,650
Accretion expense	3,317		3,990		10,674		11,695
General and administrative	40,396		32,341		121,682		106,492
	51,461		44,807		157,483		145,837

Net income	$	219,311	$	212,692	$	597,212	$	599,150

Net income allocated to:

Managing General Partner	$	21,931	$	21,269	$	59,721	$	59,915

Limited Partners	$	197,380	$	191,423	$	537,491	$	539,235

Per limited partner unit	$	13.16	$	12.76	$	35.83	$	35.95

The accompanying notes are an integral
part of these financial statements.

Table of Contents

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

Statements of Cash Flows

(unaudited)

	Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities:

Cash received from income from net profits interests	$	775,075		$	784,139
Cash paid to suppliers	(121,682		)	(106,492		)
Interest received	367			253
Net cash provided by operating activities	653,760			677,900

Cash flows used in financing activities:

Distributions to partners	(578,439		)	(627,017		)

Net increase in cash and cash equivalents	75,321			50,883

Beginning of period	121,184			70,853

End of period	$	196,505		$	121,736

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

Net income	$	597,212		$	599,150

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

Depreciation, depletion and amortization	25,127			27,650
Accretion expense	10,674			11,695
Settlement of asset retirement obligation for plugged and abandoned wells	(44,115		)	—
Decrease in receivables	64,862			39,405
Net cash provided by operating activities	$	653,760		$	677,900

Noncash investing and financing activities:

Increase in oil and gas properties – Asset retirement obligations	$	—		$	957

The accompanying notes are an integral
part of these financial statements.

Table of Contents

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

Notes to Financial Statements

1. Organization

Southwest Royalties Institutional Income Fund VII-B, L.P. was organized under the laws of the state of Delaware on January 28, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc., 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
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
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	90	%	10	%
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year, which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2. Summary of Significant Accounting Policies

The interim financial information as of September 30, 2011, and for the three and nine months ended September 30, 2011, 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, 2010.

3. Abandonment Obligations

The Partnership follows the provisions of ASC topic 410-20, formerly SFAS No. 143, “Accounting for Asset Retirement Obligations”. 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.

Our asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

Table of Contents

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

Notes to Financial Statements

3. Abandonment Obligations — continued

Changes in abandonment obligations for the nine months ended September 30, 2011 and 2010 are as follows:

	2011			2010
Beginning of period	$	211,782		$	195,064
Reduction of obligations for plugged and abandoned wells	(44,115		)	—
Revisions of estimates	—			957
Accretion expense	10,674			11,695
End of period	$	178,341		$	207,716

4. Subsequent Events

The Partnership has evaluated events and transactions that occurred after the balance sheet date of September 30, 2011 and has determined that no events or transactions have occurred, other than the one shown below, that would require recognition in the financial statements or disclosures in these notes to the financial statements.

On October 28, 2011, the Partnership, entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Southwest Royalties, Inc., (“SWR”), pursuant to which the Partnership will be merged with and into SWR (the “Merger”) with SWR surviving the Merger. Pursuant to the terms of the Merger Agreement, at the effective time of the Merger (the “Effective Time), each unit representing a limited partnership interest in the Partnership (“Unit”) outstanding immediately prior to the Effective Time, other than Units held by SWR, will be converted into the right to receive cash in an amount equal to $275.54 less the sum of the per Unit cash distributions made after September 30, 2011, if any. SWR will not receive any cash payment for its Units; however, as a result of the Merger, SWR will acquire 100% of the assets and liabilities of the Partnership.

Table of Contents

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

General

Southwest Royalties Institutional Income Fund VII-B, L.P. was organized as a Delaware limited partnership on January 28, 1987. The offering of such limited partnership interests began on March 23, 1987. Minimum capital requirements were met on May 20, 1987 and the offering concluded on December 1, 1987, with total limited partner contributions of $7.5 million.

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 or revenues. 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, 2011, 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, 2011, there were no timing differences, which resulted in a deficit net profit interest.

Table of Contents

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. Current SEC financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report. The ceiling calculation dictates that those prices be held constant. Because the ceiling calculation dictates that prices and costs 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 can be either substantially higher or lower than the Partnership’s long-term price forecast that is a barometer for true fair value.

Table of Contents

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,
	2011		2010
Oil production in barrels	3,738		4,302
Gas production in mcf	5,607		7,612
Total (BOE)	4,673		5,571
Average price per barrel of oil	$	89.10	$	74.00
Average price per mcf of gas	$	8.41	$	5.87
Partnership distributions	$	125,000	$	150,000
Limited partner distributions	$	112,500	$	135,000
Per unit distribution to limited partners	$	7.50	$	9.00
Number of limited partner units	15,000		15,000

Operating Results

The following discussion compares our results for the quarters ended September 30, 2011 and 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective quarterly period.

Revenue

Comparing 2011 to 2010, oil and gas sales increased $17,231, of which price variances accounted for a $70,727 increase and production variances accounted for a $53,496 decrease.

Production in 2011 (on a BOE basis) was 16% lower than 2010. Our oil production was 13% lower in 2011 than 2010 due primarily to production declines on two properties. Our gas production was 26% lower in 2011 than 2010 due primarily to production decline on one field.

In 2011, our realized oil price was 20% higher than 2010, while our realized gas price was 43% higher. The average realized price per mcf includes the value received for the natural gas liquids component of the price received for processed natural gas. 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 increased from $18.95 per BOE in 2010 to $23.45 per BOE in 2011. The increase in oil and gas production costs was due primarily to the increase in production taxes resulting from the increase in revenue.

Expenses

Depletion on a BOE basis increased 9% in 2011. Comparing 2011 to 2010, depletion expense decreased $728, of which rate variances accounted for a $639 increase and production variances accounted for a $1,367 decrease.

Accretion expense decreased 17% in 2011 as compared to 2010 due primarily to the five wells that were plugged and abandoned in the second quarter of 2011.

General and administrative (“G&A”) expenses were 25% higher in 2011 due primarily to increases in professional fees.

Table of Contents

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,
	2011		2010
Oil production in barrels	11,048		11,600
Gas production in mcf	17,696		23,058
Total (BOE)	13,997		15,443
Average price per barrel of oil	$	93.48	$	75.83
Average price per mcf of gas	$	8.27	$	6.81
Partnership distributions	$	578,439	$	627,017
Limited partner distributions	$	520,410	$	564,196
Per unit distribution to limited partners	$	34.69	$	37.61
Number of limited partner units	15,000		15,000

Operating Results

The following discussion compares our results for the nine months ended September 30, 2011 and 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective nine month period.

Revenue

Comparing 2011 to 2010, oil and gas sales increased $142,536, of which price variances accounted for a $220,883 increase and production variances accounted for a $78,347 decrease.

Production in 2011 (on a BOE basis) was 9% lower than 2010. Our oil production was 5% lower in 2011 than 2010. Our gas production was 23% lower in 2011 than 2010 due primarily to production decline on one field.

In 2011, our realized oil price was 23% higher than 2010, while our realized gas price was 21% higher. The average realized price per mcf includes the value received for the natural gas liquids component of the price received for processed natural gas. 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 increased from $18.89 per BOE in 2010 to $30.34 per BOE in 2011. The increase in oil and gas production costs was due primarily to the cost to plug and abandon a well.

Expenses

Depletion on a BOE basis increased less than 1% in 2011. Comparing 2011 to 2010, depletion expense decreased $2,523, of which rate variances accounted for a $65 increase and production variances accounted for a $2,588 decrease.

Accretion expense decreased 9% in 2011 as compared to 2010.

General and administrative (“G&A”) expenses were 14% higher in 2011 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. However 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 ending September 30, 2011 were $578,439, of which $520,410 was distributed to the limited partners and $58,029 to the general partners. Cumulative cash distributions of $20,259,450 have been made to the general and limited partners as of September 30, 2011. As of September 30, 2011, $18,247,816 or $1,216.52 per limited partner unit has been distributed to the limited partners, representing 243% of contributed capital.

Table of Contents

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 the 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

No changes in internal control over financial reporting were made during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

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, 2010, as filed with the U.S. Securities and Exchange Commission on March 31, 2011 and available at www.sec.gov. There have been no material changes to these risk factors since the filing of our Form 10-K.

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

None

Item 3. Defaults Upon Senior Securities

None

Item 4. (Removed and Reserved)

None

Item 5. Other Information

None

Item 6. Exhibits

(a) Exhibits:

2.1		Agreement and Plan of Merger dated October 28, 2011 by and between Southwest Royalties, Inc. and Southwest Royalties Institutional Income Fund VII-B, L.P., filed as Exhibit 2.2 to our Current Report on Form 8-K filed with the Commission on November 2, 2011.

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

101.INS		XBRL Instance Document

101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.DEF		XBRL Definition Linkbase Document

101.LAB		XBRL Labels Linkbase Document

101.PRE		XBRL Presentation Linkbase Document

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Southwest Royalties Institutional Income Fund
		VII-B, L.P., a Delaware limited partnership

	By:	Southwest Royalties, Inc., Managing
		General Partner


	By:	/s/ Mel G. Riggs
		Mel G. Riggs
		President and Chief Executive Officer

	Date:	November 14, 2011

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B L P 10-Q