10-Q 1 a9300810q209.htm QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) a9300810q209.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, 2008

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 0-16493


Southwest Oil & Gas Income Fund VII-A, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)

Delaware
 
75-2145576
(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 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.


 
1

 


 
Table of Contents
 
     
   
Page
 
Glossary                                                                                                                        
3
     
 
Part I - FINANCIAL INFORMATION
 
     
Financial Statements                                                                                                                        
5
     
 
Balance Sheets as of September 30, 2008 and December 31, 2007                                                                                                                        
6
     
 
7
     
 
8
     
11
     
Quantitative and Qualitative Disclosures About Market Risk                                                                                                                        
16
     
Controls and Procedures                                                                                                                        
16
     
     
 
Part II – OTHER INFORMATION
 
     
Legal Proceedings                                                                                                                        
18
     
Risk Factors                                                                                                                        
18
     
Unregistered Sales of Equity Securities and Use of Proceeds                                                                                                                        
18
     
Defaults Upon Senior Securities                                                                                                                        
18
     
Submission of Matter to a Vote of Security Holders                                                                                                                        
18
     
Other Information                                                                                                                        
18
     
Exhibits                                                                                                                        
18
     
 
Signatures                                                                                                                        
19

 
2

 

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.

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.





 
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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.



 
4

 

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, 2007, which are found in the Registrant's Form 10-K Report for 2007 filed with the Securities and Exchange Commission.  The December 31, 2007 balance sheet included herein has been taken from the Registrant's 2007 Form 10-K Report.  Operating results for the three and nine-month periods ended September 30, 2008 are not necessarily indicative of the results that may be expected for the full year.

 
5

 

Southwest Oil & Gas Income Fund VII-A, L.P.
Balance Sheets



   
September 30,
   
December 31,
 
   
2008
   
2007
 
   
(unaudited)
       
Assets
           
Current assets:
           
Cash and cash equivalents
  $ 62,187     $ 76,602  
Receivable from Managing General Partner
    261,755       169,905  
State income tax deposits
    4,451       4,646  
Total current assets
    328,393       251,153  
                 
Oil and gas properties - using the full-
               
cost method of accounting
    4,786,708       4,861,742  
Less accumulated depreciation,
               
depletion and amortization
    4,305,617       4,273,348  
Net oil and gas properties
    481,091       588,394  
                 
    $ 809,484     $ 839,547  
                 
Liabilities and Partners' Equity (Deficit)
               
                 
Asset retirement obligation
  $ 424,942     $ 479,794  
                 
Partners' equity (deficit):
               
General partner
    (596,016 )     (598,504 )
Limited partners
    980,558       958,257  
Total partners' equity
    384,542       359,753  
                 
    $ 809,484     $ 839,547  
                 






















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

 
6

 

Southwest Oil & Gas Income Fund VII-A, L.P.
Statements of Operations
(unaudited)


   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2008
   
2007
   
2008
   
2007
 
Revenues
                       
                         
Oil and gas
  $ 553,625     $ 367,668     $ 1,655,071     $ 1,044,107  
Interest
    303       1,013       994       2,680  
Other income
    -       -       99       -  
                                 
      553,928       368,681       1,656,164       1,046,787  
                                 
Expenses
                               
                                 
Production
    106,146       91,624       380,550       286,479  
Depreciation, depletion and amortization
    10,242       11,599       32,269       33,402  
Accretion expense
    9,342       10,325       25,797       29,847  
General and administrative
    31,845       33,595       106,318       95,390  
                                 
      157,575       147,143       544,934       445,118  
                                 
Net income
  $ 396,353     $ 221,538     $ 1,111,230     $ 601,669  
                                 
Net income allocated to:
                               
Managing General Partner
  $ 39,635     $ 22,154     $ 111,123     $ 60,167  
                                 
Limited partners
  $ 356,718     $ 199,384     $ 1,000,107     $ 541,502  
                                 
Per limited partner unit
  $ 23.78     $ 13.29     $ 66.67     $ 36.10  
                                 























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

 
7

 

Southwest Oil & Gas Income Fund VII-A, L.P.
Statements of Cash Flows
(unaudited)


   
Nine Months Ended
 
   
September 30,
 
   
2008
   
2007
 
Cash flows from operating activities:
           
             
Cash received from oil and gas sales
  $ 1,563,416     $ 1,015,693  
Cash paid to suppliers
    (486,868 )     (381,869 )
Interest received
    994       2,680  
Miscellaneous settlement with general partner
    99       44,527  
Net cash provided by operating activities
    1,077,641       681,031  
                 
Cash flows used in investing activities:
               
                 
Additions to oil and gas properties
    (5,615 )     (26,290 )
                 
Cash flows used in financing activities:
               
                 
Distributions to partners
    (1,086,441 )     (641,018 )
                 
Net (decrease) increase in cash and cash equivalents
    (14,415 )     13,723  
                 
Beginning of period
    76,602       64,974  
                 
End of period
  $ 62,187     $ 78,697  
                 
Reconciliation of net income to net
               
cash provided by operating activities:
               
                 
Net income
  $ 1,111,230     $ 601,669  
                 
Adjustments to reconcile net income to
               
net cash provided by operating activities:
               
                 
Depreciation, depletion and amortization
    32,269       33,402  
Accretion expense
    25,797       29,847  
(Increase) decrease in receivables
    (91,655 )     16,113  
                 
Net cash provided by operating activities
  $ 1,077,641     $ 681,031  
                 
Noncash investing and financing activities:
               
                 
(Decrease) increase in oil and gas properties – SFAS No. 143
  $ (80,649 )   $ 19,949  










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

 
8

 

Southwest Oil & Gas Income Fund VII-A, L.P.
(a Delaware limited partnership)

Notes to Financial Statements

1.      Organization
Southwest Oil & Gas Income Fund VII-A, L.P. was organized under the laws of the state of Delaware on January 30, 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 %     -  
Amortization of organization costs
    100 %     -  
Property acquisition costs
    100 %     -  
Gain/loss on property dispositions
    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, 2008, and for the three and nine months ended September 30, 2008, 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, 2007.




 
9

 

Southwest Oil & Gas Income Fund VII-A, L.P.
(a Delaware limited partnership)

Notes to Financial Statements

3.              Abandonment Obligations
The Partnership follows the provisions of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), as amended.  SFAS 143 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, 2008 and 2007 are as follows:

   
2008
   
2007
 
Beginning of period
  $ 479,794     $ 419,489  
Additional abandonment obligations from new wells
    -       19,949  
Revisions of estimates
    (80,649 )     -  
Accretion expense
    25,797       29,847  
End of period
  $ 424,942     $ 469,285  




 
10

 

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

General
Southwest Oil & Gas Income Fund VII-A, L.P. was organized as a Delaware limited partnership on January 30, 1987. The offering of limited partnership interests began on March 4, 1987, minimum capital requirements were met on April 28, 1987 and the offering concluded on September 21, 1987, with total limited partner contributions of $7.5 million.

The Partnership was formed to acquire interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties, and to distribute the net proceeds from operations to the limited and general partners.  Net revenues from producing oil and gas properties are not reinvested in other revenue producing assets except to the extent that production facilities and wells are improved or reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves.  The economic life of the Partnership thus depends on the period over which the Partnership’s oil and gas reserves are economically recoverable.

Increases or decreases in Partnership revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, increases and decreases in lease operating expenses, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements, sales of properties, and the depletion of wells.  Since wells deplete over time, production can generally be expected to decline from year to year.

Well operating costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately.  Net income available for distribution to the partners is therefore expected to 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, 2008, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.


 
11

 

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.


 
12

 

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,
 
   
2008
   
2007
 
Oil production in barrels
    3,826       3,718  
Gas production in mcf
    10,033       12,709  
Total (BOE)
    5,498       5,836  
Average price per barrel of oil
  $ 115.98     $ 71.43  
Average price per mcf of gas
  $ 10.95     $ 8.03  
Partnership distributions
  $ 435,000     $ 250,000  
Limited partner distributions
  $ 391,500     $ 225,000  
Per unit distribution to limited partners
  $ 26.10     $ 15.00  
Number of limited partner units
    15,000       15,000  

Operating Results
The following discussion compares our results for the quarters ended September 30, 2008 and 2007.  Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective quarterly period.

Revenues
Comparing 2008 to 2007, oil and gas sales increased $185,957, of which price variances accounted for a $199,738 increase and production variances accounted for a $13,781 decrease.

Production in 2008 (on a BOE basis) was 6% lower than 2007.  Oil production in 2008 was 3% higher than 2007.  Our gas production in 2008 was 21% lower than 2007 due primarily to the production decline on one property.

In 2008, our realized oil price was 62% higher than 2007, while our realized gas price was 36% 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.

Expenses
Oil and gas production costs on a BOE basis increased from $15.70 per BOE in 2007 to $19.31 per BOE in 2008.  The increase in oil and gas production costs was due primarily to higher production taxes resulting from higher commodity prices.

Depletion on a BOE basis decreased 6% in 2008.  Comparing 2008 to 2007, depletion expense decreased $1,357, of which rate variances accounted for a $685 decrease and production variances accounted for a $672 decrease.

Accretion expense decreased 10% in 2008 due primarily to changes in estimates of asset retirement obligations.

General and administrative (“G&A”) expenses were 5% lower in 2008 as compared to 2007.


 
13

 

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,
 
   
2008
   
2007
 
Oil production in barrels
    11,763       11,648  
Gas production in mcf
    32,740       41,952  
Total (BOE)
    17,220       18,640  
Average price per barrel of oil
  $ 109.77     $ 61.21  
Average price per mcf of gas
  $ 11.11     $ 7.89  
Partnership distributions
  $ 1,086,441     $ 641,018  
Limited partner distributions
  $ 977,806     $ 576,912  
Per unit distribution to limited partners
  $ 65.19     $ 38.46  
Number of limited partner units
    15,000       15,000  

Operating Results
The following discussion compares our results for the nine months ended September 30, 2008 and 2007.  Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective nine-month period.

Revenues
Comparing 2008 to 2007, oil and gas sales increased $610,964, of which price variances accounted for a $676,642 increase and production variances accounted for a $65,678 decrease.

Production in 2008 (on a BOE basis) was 8% lower than 2007.  Our oil production in 2008 was 1% higher than 2007.  Our gas production in 2008 was 22% lower than 2007 due primarily to the production decline on one property.

In 2008, our realized oil price was 79% higher than 2007, while our realized gas price was 41% 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.

Expenses
Oil and gas production costs on a BOE basis increased from $15.37 per BOE in 2007 to $22.10 per BOE in 2008.  The increase in oil and gas production costs was due primarily to surface repairs on an injection well, higher operating costs on a property, and subsurface repairs on an oil well.  Also contributing to the increase was higher production taxes resulting from higher commodity prices.

Depletion on a BOE basis increased 5% in 2008.  Comparing 2008 to 2007, depletion expense decreased $1,133, of which rate variances accounted for a $1,412 increase and production variances accounted for a $2,545 decrease.

Accretion expense decreased 14% in 2008 due primarily to changes in estimates of asset retirement obligations.

General and administrative (“G&A”) expenses were 11% higher in 2008 due primarily to increases in professional fees.



 
14

 

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. Although House Bill 3 states that the Texas Margin Tax is not an income tax, the Partnership believes that Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”) applies to the Texas Margin Tax.  In 2008, the Managing General Partner increased its total ownership interest in the Partnership to more than 50%.  Therefore, the Partnership became subject to the Texas Margin Tax in 2008, and its profit margin will be included in the consolidated tax return filed by Clayton Williams Energy, Inc., parent of the Managing General Partner.  The Partnership does not record any provision for this tax since any Texas Margin Tax attributable to the Partnership will be paid by the Managing General Partner and the amount is not considered significant.

Settlement with General Partner
Southwest Royalties Inc. formed a redevelopment plan for the NR Colby B water flood in 1997. The development included drilling 5 additional wells, converting 7 wells to injection, drilling 2 water supply wells, workover of 4 producers, and upgrading injection and production facilities at an estimated cost of $1,547,500.  An outside consultant advised that a fair farm out arrangement would be for SWRI to pay all the costs of the development in return for 90% of the limited partnerships’ interest in the property.  The project started in December 1997 with the ownership changed effective January 1, 1998. Upon seeing a precipitous decline in oil prices in 1998 the project was cancelled after converting two wells to injection and performing a workover on one well. To satisfy the inequity that resulted from the assignment of the full 90% interest without performing all the planned development activities, SWRI assigned the 90% earned interest back to the partnership effective January 1, 2007 and paid $44,527 to the partnership for the difference between the amount paid and the pre-farm-out interest amount for years 1998 through 2006 less the development cost incurred plus interest.  Accordingly $44,527 was recognized as other income in the fourth quarter of 2006.

Liquidity and Capital Resources
Partnership distributions during the nine months ending September 30, 2008 were $1,086,441, of which $977,806 was distributed to the limited partners and $108,635 to the general partners.  Cumulative cash distributions of $15,561,605 have been made to the general and limited partners as of September 30, 2008.  As of September 30, 2008, $14,023,643 or $934.91 per limited partner unit has been distributed to the limited partners, representing 187% of contributed capital.

Recent Accounting Pronouncements
The Partnership adopted SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) (as amended) effective January 1, 2008.  SFAS 157 defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  The adoption of SFAS 157 had no effect on the Partnership.  As permitted by FSP No. 157-2, the Partnership has not applied the provisions of SFAS 157 to nonfinancial assets and liabilities relating to its asset retirement obligations.



 
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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

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
Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.  Our internal control over financial reporting includes those policies and procedures that:

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and

provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


 
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Changes in 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, 2008 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934.  Management assessed the effectiveness of our internal control over financial reporting as of September 30, 2008.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  Based on this assessment, management has concluded that, as of September 30, 2008, our internal control over financial reporting is effective based on those criteria.





 
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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, 2007, as filed with the U.S. Securities and Exchange Commission on March 28, 2008 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.                     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




 
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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 Oil & Gas Income Fund VII-A, 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 12, 2008

 
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