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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, 2004
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 of (I.R.S.
Employer
incorporation or organization)
Identification No.)
6 Desta Drive, Suite 6500
Midland, Texas 79705
(Address of principal executive offices)
432-682-6324
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:
Yes X No ___
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 23.
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.
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 the leasehold
or working interest agrees to assign his interest in certain specific
acreage to the assignee, retaining some interest, such as an overriding
royalty interest, subject to the drilling of one (1) or more wells or other
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.
Present value and PV-10 Value. When used with respect to oil and
natural gas reserves, the estimated future net revenue to be generated from
the production of proved reserves, determined in all material respects in
accordance with the rules and regulations of the SEC (generally using
prices and costs in effect as of the date indicated) without giving effect
to non-property related expenses such as general and administrative
expenses, debt service and future income tax expenses or to depreciation,
depletion and amortization, discounted using an annual discount rate of
10%.
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 developed oil and gas
reserves are reserves that can be expected to be recovered from existing
wells with existing equipment and operating methods.
Proved properties. Properties with proved reserves.
Proved reserves. The estimated quantities of crude oil, natural gas,
and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil or gas that is confined by
impermeable rock or water barriers and is individual and separate from
other reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of
costs of production.
Working interest. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property
and a share of production.
Workover. Operations on a producing well to restore or increase
production.
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the notes thereto for
the year ended December 31, 2003, which are found in the Registrant's Form
10-K Report for 2003 filed with the Securities and Exchange Commission.
The December 31, 2003 balance sheet included herein has been taken from the
Registrant's 2003 Form 10-K Report. Operating results for the three and
nine-month periods ended September 30, 2004 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
Septembe December
r 30, 31,
2004 2003
------ ------
(unaudit
ed)
Assets
- ----------
Current assets:
Cash and cash equivalents $ 79,971 72,631
Receivable from Managing 128,273 90,640
General Partner
-------- --------
---- ----
Total current assets 208,244 163,271
-------- --------
---- ----
Oil and gas properties -
using the full-
cost method of accounting 4,576,98 4,570,47
3 7
Less accumulated
depreciation,
depletion and 4,158,36 4,137,77
amortization 8 2
-------- --------
---- ----
Net oil and gas 418,615 432,705
properties
-------- --------
---- ----
$ 626,859 595,976
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability - $ 3,459 1,704
distribution payable
-------- --------
---- ----
Asset retirement obligation 188,379 177,971
-------- --------
---- ----
Partners' equity:
General partner (590,952 (592,824
) )
Limited partners 1,025,97 1,009,12
3 5
-------- --------
---- ----
Total partners' equity 435,021 416,301
-------- --------
---- ----
$ 626,859 595,976
======= =======
Southwest Oil & Gas Income Fund VII-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
---- ---- ---- ----
Revenues
- ------------
Oil and Gas $ 279,299 227,307 820,677 729,471
Interest 159 200 482 543
Other - - 250 27
--------- --------- -------- --------
- - -- --
279,458 227,507 821,409 730,041
--------- --------- -------- --------
- - -- --
Expenses
- -------------
Production 83,125 80,717 266,321 262,896
General and administrative 31,376 30,918 95,099 97,361
Accretion of asset retirement 3,554 3,296 10,673 9,858
obligation
Depreciation, depletion and 6,596 10,000 20,596 31,000
amortization
--------- --------- -------- --------
- - -- --
124,651 124,931 392,689 401,115
--------- --------- -------- --------
- - -- --
Net income before cumulative 154,807 102,576 428,720 328,926
effects
Cumulative effect of change
in accounting
principle - SFAS No. 143 - - - - (90,149)
See Note 3
--------- --------- -------- --------
- - -- --
Net income $ 154,807 102,576 428,720 238,777
====== ====== ====== ======
Net income allocated to:
Managing General Partner $ 15,481 10,258 42,872 23,878
====== ====== ====== ======
Limited Partners $ 139,326 92,318 385,848 214,899
====== ====== ====== ======
Per limited partner unit $ 9.29 6.15 25.72
before cumulative effect 19.74
Cumulative effects per - - - (5.41)
limited partner unit
--------- --------- -------- --------
- - -- --
Per limited partner unit $ 9.29 6.15 25.72
14.33
====== ====== ====== ======
Southwest Oil & Gas Income Fund VII-A, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
2004 2003
----- -----
Cash flows from operating
activities
Cash received from oil and gas $ 774,598 701,890
sales
Cash paid to suppliers (352,974) (329,419)
Interest received 482 543
Miscellaneous settlement 250 27
--------- ---------
- -
Net cash provided by operating 422,356 373,041
activities
--------- ---------
- -
Cash flows from investing
activities
Sale of oil and gas property - 38
Additions to oil and gas (6,771) (8,809)
properties
--------- ---------
- -
Net cash used in investing (6,771) (8,771)
activities
--------- ---------
- -
Cash flows used in financing
activities
Distributions to partners (408,245) (314,965)
--------- ---------
- -
Net increase in cash and cash 7,340 49,305
equivalents
Beginning of period 72,631 33,580
--------- ---------
- -
End of period $ 79,971 82,885
====== ======
Reconciliation of net income to
net cash
provided by operating activities
Net income $ 428,720 238,777
Adjustments to reconcile net
income to net
cash provided by operating
activities
Depreciation, depletion and 20,596 31,000
amortization
Accretion of asset retirement 10,673 9,858
obligation
Cumulative effect of change in
accounting
principle - SFAS No. 143 - 90,149
Increase in receivables (46,079) (27,581)
Increase in payables 8,446 30,838
--------- ---------
- -
Net cash provided by operating $ 422,356 373,041
activities
====== ======
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption
of SFAS No. 143 $ - 73,903
====== ======
Increase in oil and gas
properties - SFAS No. 143
additional well from farmout $ - 765
arrangement
====== ======
Decrease in oil and gas
properties - SFAS No. 143
plug and abandoned well $ 265 -
====== ======
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 100% -
contributions
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and offering 100% -
costs (1)
Amortization of organization 100% -
costs
Property acquisition costs 100% -
Gain/loss on property 90% 10%
dispositions
Operating and administrative 90% 10%
costs (2)
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, 2004, and for
the three and nine months ended September 30, 2004, 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, 2003.
3. Cumulative effect of change in accounting principle - SFAS No. 143
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required
for all companies with fiscal years beginning after June 15, 2002.
The new standard 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 to capitalize an equal
amount as a cost of the asset and depreciate the additional cost over
the estimated useful life of the asset. On January 1, 2003, the
Partnership recorded additional costs, net of accumulated
depreciation, of approximately $73,903, a long term liability of
approximately $164,052 and a loss of approximately $90,149 for the
cumulative effect on depreciation of the additional costs and
accretion expense on the liability related to expected abandonment
costs of its oil and natural gas producing properties. At September
30, 2004, the asset retirement obligation was $188,379. The increase
in the asset retirement obligation from January 1, 2004 is due to
accretion expense of $10,673, partially offset by a decrease of $265
due to the plugging and abandonment of a well.
Southwest Oil & Gas Income Fund VII-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Change in Control of Managing General Partner
On May 21, 2004, Clayton Williams Energy, Inc. acquired all the
outstanding common stock of Southwest Royalties Inc. through a merger.
Clayton Williams Energy, Inc. paid $57.1 million to holders of
Southwest Royalties, Inc. common stock and common stock warrants
($45.01 per share) and assumed and refinanced approximately
$113.9 million of assumed bank debt at closing.
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 $7,500,000.
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 farmout arrangements, sale of
properties, and the depletion of wells. Since wells deplete over time,
production can generally be expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to fluctuate in later years based on these factors.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
involved.
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, 2004, 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. Quarterly reserve estimates
are prepared by the Managing General Partner's internal staff of engineers.
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 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.
Results of Operations
A. General Comparison of the Quarters Ended September 30, 2004 and 2003
The following table provides certain information regarding performance
factors for the quarters ended September 30, 2004 and 2003:
Three Months
Ended Percenta
ge
September 30, Increase
2004 2003 (Decreas
e)
---- ---- --------
--
Average price per barrel of $ 40.81 42%
oil 28.81
Average price per mcf of gas $ 5.53 24%
4.47
Oil production in barrels 4,260 4,400 (3%)
Gas production in mcf 19,078 22,500 (15%)
Oil and gas revenue $ 279,299 227,307 23%
Production expense $ 83,125 80,717 3%
Partnership distributions $ 150,000 120,000 25%
Limited partner $ 135,000 108,000 25%
distributions
Per unit distribution to
limited
partners $ 9.00 25%
7.20
Number of limited partner 15,000 15,000
units
Revenues
The Partnership's oil and gas revenues increased to $279,299 from $227,307
for the quarters ended September 30, 2004 and 2003, respectively, an
increase of 23%. The principal factors affecting the comparison of the
quarters ended September 30, 2004 and 2003 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended September 30, 2004 as compared to the
quarter ended September 30, 2003 by 42%, or $12.00 per barrel, resulting in
an increase of approximately $51,100 in revenues. Oil sales represented
62% of total oil and gas sales during the quarter ended September 30, 2004
as compared to 56% during the quarter ended September 30, 2003.
The average price for an mcf of gas received by the Partnership
increased during the same period by 24%, or $1.06 per mcf, resulting in
an increase of approximately $20,200 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $71,300. The market price
for oil and gas has been extremely volatile over the past decade and
management expects a certain amount of volatility to continue in the
foreseeable future.
2. Oil production decreased approximately 140 barrels or 3% during the
quarter ended September 30, 2004 as compared to the quarter ended
September 30, 2003, resulting in a decrease of approximately $4,000 in
revenues.
Gas production decreased approximately 3,422 mcf or 15% during the same
period, resulting in a decrease of approximately $15,300 in revenues.
The total decrease in revenues due to the change in production is
approximately $19,300. The decrease in gas production is primarily due
to a steep decline on one property.
Costs and Expenses
Total costs and expenses decreased to $124,651 from $124,931 for the
quarters ended September 30, 2004 and 2003, respectively, a decrease of
less than 1%. The decrease is the result of lower depletion expense,
partially offset by an increase in lease operating costs, accretion expense
and general and administrative expense.
1. Lease operating costs and production taxes were 3% higher or
approximately $2,400 more during the quarter ended September 30, 2004 as
compared to the quarter ended September 30, 2003.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 2%
or approximately $500 during the quarter ended September 30, 2004 as
compared to the quarter ended September 30, 2003.
3. Depletion expense decreased to $6,596 for the quarter ended September
30, 2004 from $10,000 for the same period in 2003. This represents a
decrease of 34%. The contributing factor to the decrease in depletion
expense is in relation to the BOE depletion rate for the quarter ended
September 30, 2004, which was $.89 applied to 7,440 BOE as compared to
$1.23 applied to 8,150 BOE for the same period in 2003. The lower
depreciation rate in 2004 is due to the upward revision in reserve
estimates resulting from higher oil and gas prices.
4. Accretion expense increased to $3,554 for the quarter ended September
30, 2004 from $3,296 for the same period in 2004. This represents an
increase of 8%.
B. General Comparison of the Nine-Month Periods Ended September 30, 2004
and 2003
The following table provides certain information regarding performance
factors for the nine-month periods ended September 30, 2004 and 2003:
Nine Months
Ended Percenta
ge
September 30, Increase
2004 2003 (Decreas
e)
---- ---- --------
--
Average price per barrel of $ 36.15 23%
oil 29.39
Average price per mcf of gas $ 5.72 12%
5.10
Oil production in barrels 13,350 13,200 1%
Gas production in mcf 59,148 67,000 (12%)
Oil and gas revenue $ 820,677 729,471 13%
Production expense $ 266,321 262,896 1%
Partnership distribution $ 410,000 315,000 30%
Limited partner $ 369,000 283,500 30%
distributions
Per unit distribution to
limited
partners $ 24.60 30%
18.90
Number of limited partner 15,000 15,000
units
Revenues
The Partnership's oil and gas revenues increased to $820,677 from $729,471
for the nine months ended September 30, 2004 and 2003, respectively, an
increase of 13%. The principal factors affecting the comparison of the
nine months ended September 30, 2004 and 2003 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the nine months ended September 30, 2004 as compared
to the nine months ended September 30, 2003 by 23%, or $6.76 per
barrel, resulting in an increase of approximately $90,200 in revenues.
Oil sales represented 59% of total oil and gas sales during the nine
months ended September 30, 2004 as compared to 53% during the nine
months ended September 30, 2003.
The average price for an mcf of gas received by the Partnership
increased during the same period by 12%, or $.62 per mcf, resulting in
an increase of approximately $36,700 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $126,900. The market
price for oil and gas has been extremely volatile over the past decade
and management expects a certain amount of volatility to continue in
the foreseeable future.
2. Oil production increased approximately 150 barrels or 1% during the
nine months ended September 30, 2004 as compared to the nine months
ended September 30, 2003, resulting in an increase of approximately
$4,400 in revenues.
Gas production decreased approximately 7,852 mcf or 12% during the
same period, resulting in a decrease of approximately $40,000 in
revenues.
The net total decrease in revenues due to the change in production is
approximately $35,600. The decrease in gas production is primarily
due to a steep decline on one property.
Costs and Expenses
Total costs and expenses decreased to $392,689 from $401,115 for the nine
months ended September 30, 2004 and 2003, respectively, a decrease of 2%.
The decrease is the result of lower general and administrative expense and
depletion expense, partially offset by an increase in accretion expense and
lease operating expense.
1. Lease operating costs and production taxes were 1% higher, or
approximately $3,400 more during the nine months ended September 30,
2004 as compared to the nine months ended September 30, 2003.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased 2%
or approximately $2,300 during the nine months ended September 30, 2004
as compared to the nine months ended September 30, 2003.
3. Depletion expense decreased to $20,596 for the nine months ended
September 30, 2004 from $31,000 for the same period in 2003. This
represents a decrease of 34%. The contributing factor to the decrease
in depletion expense is in relation to the BOE depletion rate for the
nine months ended September 30, 2004, which was $.89 applied to 23,208
BOE as compared to $1.27 applied to 24,367 BOE for the same period in
2003. The lower depreciation rate in 2004 is due to the upward
revision in reserve estimates resulting from higher oil and gas prices.
4. Accretion expense increased to $10,673 for the nine months ended
September 30, 2004 from $9,858 for the same period in 2004. This
represents an increase of 8%.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $422,400 in
the nine months ended September 30, 2004 as compared to approximately
$373,000 in the nine months ended September 30, 2003.
Cash flows used in investing activities were approximately $6,800 in the
nine months ended September 30, 2004 as compared to approximately $8,800 in
the nine months ended September 30, 2003. The principle use of the 2004
cash flow from investing activities was the change in oil and gas
properties.
Cash flows used in financing activities were approximately $408,200 in the
nine months ended September 30, 2004 as compared to approximately $315,000
in the nine months ended September 30, 2003. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 2004 were
$410,000 of which $369,000 was distributed to the limited partners and
$41,000 to the general partner. The per unit distribution to limited
partners during the nine months ended September 30, 2004 was $24.60. Total
distributions during the nine months ended September 30, 2003 were $315,000
of which $283,500 was distributed to the limited partners and $31,500 to
the general partners. The per unit distribution to limited partners during
the nine months ended September 30, 2003 was $18.90.
The source for the 2004 distributions of $410,000 was oil and gas
operations of approximately $422,400, and the change in oil and gas
properties of approximately $(6,800), resulting in excess cash for
contingencies or subsequent distributions. The source for the 2003
distributions of $315,000 was oil and gas operations of approximately
$373,000, partially offset by a change in oil and gas properties of
approximately $(8,800), resulting in excess cash for contingencies or
subsequent distributions.
Cumulative cash distributions of $11,911,663 have been made to the
partners. As of September 30, 2004, $10,738,711 or $715.91 per limited
partner unit has been distributed to the limited partners, representing a
100% return of the capital and a 43% return on capital contributed.
As of September 30, 2004, the Partnership had approximately $204,800 in
working capital. The Managing General Partner knows of no unusual
contractual commitments. The partnership held many long-lived properties
at inception, however due to the restrictions on property development
imposed by the partnership agreement, the Partnership cannot develop its
non producing properties. Without continued development, the producing
reserves continue to deplete. Accordingly, as the Partnership's properties
have matured and depleted, the net cash flows from operations for the
partnership has steadily declined, except in periods of substantially
increased commodity pricing. Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production. As the
properties continue to deplete, maintenance of properties and
administrative costs as a percentage of production are expected to continue
to increase.
Managing General Partner
On May 21, 2004, Clayton Williams Energy, Inc. acquired all the outstanding
common stock of Southwest Royalties Inc. through a merger. Clayton
Williams Energy, Inc. paid $57.1 million to holders of Southwest Royalties,
Inc. common stock and common stock warrants ($45.01 per share) and assumed
and refinanced approximately $113.9 million of assumed bank debt at
closing.
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
As of the nine months ended September 30, 2004, L. Paul Latham, President
and Chief Executive Officer of the Managing General Partner, and Mel G.
Riggs, Vice President and Chief Financial Officer of the Managing General
Partner, evaluated the effectiveness of the Partnership's disclosure
controls and procedures. Based on their evaluation, they believe that:
The disclosure controls and procedures of the Partnership were
effective in ensuring that information required to be disclosed by the
Partnership in the reports it files or submits under the Exchange Act
was recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms; and
The disclosure controls and procedures of the Partnership were
effective in ensuring that material information required to be
disclosed by the Partnership in the report it filed or submitted under
the Exchange Act was accumulated and communicated to the Managing
General Partner's management, including its Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
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, 2004 that has materially affected, or is reasonably likely to
materially affect, internal control over financial reporting.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section
1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
32.2 Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section
1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
(b) No reports on Form 8-K were filed during
the quarter for which this
report is filed.
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 OIL & GAS
INCOME FUND VII-A, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial Officer
Date: November 15, 2004
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest Oil &
Gas Income Fund VII-A, L.P.
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: November 15, 2004 /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund VII-A,
L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest Oil &
Gas Income Fund VII-A. L.P.,
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: November 15, 2004 /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund VII-A,
L.P.
CERTIFICATION PURSUANT TOExhibit 32.1
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Oil & Gas Income
Fund VII-A, L. P. (the "Company") on Form 10-Q for the period ending
September 30, 2004 as filed with the Securities and Exchange Commission on
the date hereof (the "Report"), I, L. Paul Latham, Chief Executive Officer
of the Managing General Partner of the Company, certify, pursuant to 18
U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of
2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and results
of operation of the
Company.
Date: November 15, 2004
L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund VII-A, L.P.
CERTIFICATION PURSUANT TOExhibit 32.2
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Oil & Gas Income
Fund VII-A, L. P. (the "Company") on Form 10-Q for the period ending
September 30, 2004 as filed with the Securities and Exchange Commission on
the date hereof (the "Report"), I, Mel G. Riggs, Chief Financial Officer of
the Managing General Partner of the Company, certify, pursuant to 18 U.S.C.
1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002,
that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and
results of operation of the
Company.
Date: November 15, 2004
/s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund VII-A, L.P.