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
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75-2145576
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(State
or other jurisdiction
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(I.R.S.
Employer
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of
incorporation or organization)
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Identification
No.)
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6 Desta Drive, Suite 6500, Midland,
Texas
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79705
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(Address
of principal executive office)
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(Zip
Code)
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(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 ¨
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Accelerated
filer ¨
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Non-accelerated
filer x
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Smaller
reporting company ¨
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Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
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¨
Yes
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x
No
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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.
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Table of Contents
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Page
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3
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Part
I - FINANCIAL INFORMATION
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5
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6
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7
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8
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11
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16
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16
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Part
II – OTHER INFORMATION
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18
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18
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18
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18
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18
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18
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18
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19
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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.
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, 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.
Southwest
Oil & Gas Income Fund VII-A, L.P.
Balance
Sheets
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September
30,
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December
31,
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2008
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2007
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(unaudited)
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Assets
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Current
assets:
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Cash and cash
equivalents
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$ |
62,187 |
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$ |
76,602 |
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Receivable from Managing General
Partner
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261,755 |
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169,905 |
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State income tax
deposits
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4,451 |
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4,646 |
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Total current
assets
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328,393 |
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251,153 |
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Oil
and gas properties - using the full-
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cost method of
accounting
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4,786,708 |
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4,861,742 |
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Less accumulated
depreciation,
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depletion and
amortization
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4,305,617 |
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4,273,348 |
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Net oil and gas
properties
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481,091 |
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588,394 |
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$ |
809,484 |
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$ |
839,547 |
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Liabilities and Partners' Equity
(Deficit)
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Asset
retirement obligation
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$ |
424,942 |
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$ |
479,794 |
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Partners'
equity (deficit):
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General partner
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(596,016 |
) |
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(598,504 |
) |
Limited partners
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980,558 |
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958,257 |
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Total partners'
equity
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384,542 |
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359,753 |
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$ |
809,484 |
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$ |
839,547 |
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The
accompanying notes are an integral
part of
these financial statements.
Southwest
Oil & Gas Income Fund VII-A, L.P.
Statements
of Operations
(unaudited)
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Three
Months Ended
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Nine
Months Ended
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September
30,
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September
30,
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2008
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2007
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2008
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2007
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Revenues
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Oil
and gas
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$ |
553,625 |
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$ |
367,668 |
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$ |
1,655,071 |
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$ |
1,044,107 |
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Interest
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303 |
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1,013 |
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994 |
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2,680 |
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Other
income
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- |
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- |
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99 |
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- |
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553,928 |
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368,681 |
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1,656,164 |
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1,046,787 |
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Expenses
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Production
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106,146 |
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91,624 |
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380,550 |
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286,479 |
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Depreciation,
depletion and amortization
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10,242 |
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11,599 |
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32,269 |
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33,402 |
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Accretion
expense
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9,342 |
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10,325 |
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25,797 |
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29,847 |
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General
and administrative
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31,845 |
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33,595 |
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106,318 |
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95,390 |
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157,575 |
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147,143 |
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544,934 |
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445,118 |
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Net
income
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$ |
396,353 |
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$ |
221,538 |
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$ |
1,111,230 |
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$ |
601,669 |
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Net
income allocated to:
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Managing General
Partner
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$ |
39,635 |
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$ |
22,154 |
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$ |
111,123 |
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$ |
60,167 |
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Limited partners
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$ |
356,718 |
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$ |
199,384 |
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$ |
1,000,107 |
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$ |
541,502 |
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Per limited partner
unit
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$ |
23.78 |
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$ |
13.29 |
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$ |
66.67 |
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$ |
36.10 |
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The
accompanying notes are an integral
part of
these financial statements.
Statements
of Cash Flows
(unaudited)
|
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Nine
Months Ended
|
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September
30,
|
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2008
|
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|
2007
|
|
Cash
flows from operating activities:
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|
|
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Cash received from oil and gas
sales
|
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$ |
1,563,416 |
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$ |
1,015,693 |
|
Cash paid to
suppliers
|
|
|
(486,868 |
) |
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|
(381,869 |
) |
Interest
received
|
|
|
994 |
|
|
|
2,680 |
|
Miscellaneous settlement with
general partner
|
|
|
99 |
|
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|
44,527 |
|
Net cash provided by operating
activities
|
|
|
1,077,641 |
|
|
|
681,031 |
|
|
|
|
|
|
|
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|
|
Cash
flows used in investing activities:
|
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|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
Additions to oil and gas
properties
|
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|
(5,615 |
) |
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|
(26,290 |
) |
|
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Cash
flows used in financing activities:
|
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|
|
|
|
|
|
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|
|
|
|
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|
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Distributions to
partners
|
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|
(1,086,441 |
) |
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|
(641,018 |
) |
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|
|
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|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(14,415 |
) |
|
|
13,723 |
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|
|
|
|
|
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|
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|
Beginning
of period
|
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|
76,602 |
|
|
|
64,974 |
|
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|
|
|
|
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End
of period
|
|
$ |
62,187 |
|
|
$ |
78,697 |
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|
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Reconciliation
of net income to net
|
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|
|
|
|
|
|
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cash provided by operating
activities:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
1,111,230 |
|
|
$ |
601,669 |
|
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|
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Adjustments
to reconcile net income to
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|
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|
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net cash provided by operating
activities:
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
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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.
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:
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Limited
|
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|
General
|
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|
|
Partners
|
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|
Partners
|
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Interest
income on capital contributions
|
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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.
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 |
|
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.
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.
Critical Accounting
Policies
The
Partnership follows the full cost method of accounting for its oil and gas
properties. The full cost method subjects companies to quarterly
calculations of a “ceiling”, or limitation on the amount of properties that can
be capitalized on the balance sheet. If the Partnership’s capitalized
costs are in excess of the calculated ceiling, the excess must be written off as
an expense.
The
Partnership’s discounted present value of its proved oil and natural gas
reserves is a major component of the ceiling calculation, and represents the
component that requires the most subjective judgments. Estimates of
reserves are forecasts based on engineering data, projected future rates of
production and the timing of future expenditures. The process of
estimating oil and natural gas reserves requires substantial judgment, resulting
in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates
of reserve quantities based on the same data. The Partnership’s
reserve estimates are prepared by outside consultants.
The
passage of time provides more qualitative information regarding estimates of
reserves, and revisions are made to prior estimates to reflect updated
information. However, there can be no assurance that more significant
revisions will not be necessary in the future. If future significant
revisions are necessary that reduce previously estimated reserve quantities, it
could result in a full cost property writedown. In addition to the
impact of these estimates of proved reserves on calculation of the ceiling,
estimates of proved reserves are also a significant component of the calculation
of depletion, depreciation, and amortization (“DD&A”).
While the
quantities of proved reserves require substantial judgment, the associated
prices of oil and natural gas reserves that are included in the discounted
present value of the reserves do not require judgment. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are generally held constant indefinitely. Because the ceiling calculation
dictates that prices in effect as of the last day of the applicable quarter are
held constant indefinitely, the resulting value is not indicative of the true
fair value of the reserves. Oil and natural gas prices have
historically been cyclical and, on any particular day at the end of a quarter,
can be either substantially higher or lower than the Partnership’s long-term
price forecast that is a barometer for true fair value.
Supplemental
Information
The
following unaudited information is intended to supplement the financial
statements included in this Form 10-Q with data that is not readily available
from those statements.
|
|
Three
Months Ended
|
|
|
|
September
30,
|
|
|
|
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.
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.
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.
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.
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.
PART
II. - OTHER INFORMATION
Item
1. Legal
Proceedings
None
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
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
|
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
|
19