Attached files
file | filename |
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EX-31.2 - CERTFICATION OF CFO - SOUTHWEST OIL & GAS INCOME FUND VII A L P | mel9300931_2209.htm |
EX-31.1 - CERTIFICATION OF CEO - SOUTHWEST OIL & GAS INCOME FUND VII A L P | paul9300931_1209.htm |
EX-32.1 - CERTIFICATION OF CEO & CFO - SOUTHWEST OIL & GAS INCOME FUND VII A L P | paulmel9300932_1209.htm |
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
(Mark
One)
x QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF
1934
For the
quarterly period ended September 30, 2009
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 has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of Regulation S-T
(§232.405 of this chapter) during the preceding 12 months (or for such
shorter period that the registrant was required to submit and post such
files).
|
|
¨
Yes
|
¨
No
|
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition
of “accelerated filer and large accelerated filer” in Rule 12b-2 of the
Exchange Act.
|
||||||
Large
accelerated filer ¨
|
Accelerated
filer ¨
|
Non-accelerated
filer x
|
Smaller
reporting company¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
|
|
¨
Yes
|
x
No
|
1
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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17
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17
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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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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.
3
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, 2008, which are found in the Registrant's Annual Report
on Form 10-K for the year ended December 31, 2008 filed with the Securities and
Exchange Commission. The December 31, 2008 balance sheet included
herein has been taken from the Registrant's Annual Report on Form 10-K for the
year ended December 31, 2008. Operating results for the three
and nine month periods ended September 30, 2009 are not necessarily indicative
of the results that may be expected for the full year.
5
Southwest Oil & Gas Income Fund VII-A, L.P.
Balance
Sheets
September
30,
|
December
31,
|
|||||||
2009
|
2008
|
|||||||
(unaudited)
|
||||||||
Assets
|
||||||||
Current
assets:
|
||||||||
Cash and cash
equivalents
|
$ | 45,631 | $ | 63,005 | ||||
Receivable from Managing General
Partner
|
37,772 | - | ||||||
State income tax
deposits
|
476 | 4,470 | ||||||
Total current
assets
|
83,879 | 67,475 | ||||||
Oil
and gas properties - using the full-
|
||||||||
cost method of
accounting
|
4,838,046 | 4,798,030 | ||||||
Less accumulated
depreciation,
|
||||||||
depletion and
amortization
|
4,345,653 | 4,317,173 | ||||||
Net oil and gas
properties
|
492,393 | 480,857 | ||||||
$ | 576,272 | $ | 548,332 | |||||
Liabilities and Partners' Equity
(Deficit)
|
||||||||
Current
liability:
|
||||||||
Payable to Managing General
Partner
|
$ | - | $ | 13,296 | ||||
Asset
retirement obligation
|
475,227 | 434,589 | ||||||
Partners'
equity (deficit):
|
||||||||
General partner
|
(624,372 | ) | (624,426 | ) | ||||
Limited partners
|
725,417 | 724,873 | ||||||
Total partners'
equity
|
101,045 | 100,447 | ||||||
$ | 576,272 | $ | 548,332 | |||||
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,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
||||||||||||||||
Oil
and gas
|
$ | 213,505 | $ | 553,625 | $ | 591,355 | $ | 1,655,071 | ||||||||
Interest
|
31 | 303 | 64 | 994 | ||||||||||||
Other
income
|
- | - | 12 | 99 | ||||||||||||
213,536 | 553,928 | 591,431 | 1,656,164 | |||||||||||||
Expenses
|
||||||||||||||||
Production
|
91,123 | 106,146 | 293,547 | 380,550 | ||||||||||||
Depreciation,
depletion and amortization
|
7,261 | 10,242 | 28,480 | 32,269 | ||||||||||||
Accretion
expense
|
10,204 | 9,342 | 29,973 | 25,797 | ||||||||||||
General
and administrative
|
35,667 | 31,845 | 107,320 | 106,318 | ||||||||||||
144,255 | 157,575 | 459,320 | 544,934 | |||||||||||||
Net
income
|
$ | 69,281 | $ | 396,353 | $ | 132,111 | $ | 1,111,230 | ||||||||
Net
income allocated to:
|
||||||||||||||||
Managing General
Partner
|
$ | 6,928 | $ | 39,635 | $ | 13,211 | $ | 111,123 | ||||||||
Limited partners
|
$ | 62,353 | $ | 356,718 | $ | 118,900 | $ | 1,000,107 | ||||||||
Per limited partner
unit
|
$ | 4.16 | $ | 23.78 | $ | 7.93 | $ | 66.67 | ||||||||
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,
|
||||||||
2009
|
2008
|
|||||||
Cash
flows from operating activities:
|
||||||||
Cash received from oil and gas
sales
|
$ | 557,577 | $ | 1,563,416 | ||||
Cash paid to
suppliers
|
(432,957 | ) | (486,868 | ) | ||||
Interest
received
|
64 | 994 | ||||||
Miscellaneous
settlement
|
12 | 99 | ||||||
Net cash provided by operating
activities
|
124,696 | 1,077,641 | ||||||
Cash
flows used in investing activities:
|
||||||||
Additions to oil and gas
properties
|
(10,557 | ) | (5,615 | ) | ||||
Cash
flows used in financing activities:
|
||||||||
Distributions to
partners
|
(131,513 | ) | (1,086,441 | ) | ||||
Net
decrease in cash and cash equivalents
|
(17,374 | ) | (14,415 | ) | ||||
Beginning
of period
|
63,005 | 76,602 | ||||||
End
of period
|
$ | 45,631 | $ | 62,187 | ||||
Reconciliation
of net income to net
|
||||||||
cash provided by operating
activities:
|
||||||||
Net
income
|
$ | 132,111 | $ | 1,111,230 | ||||
Adjustments
to reconcile net income to
|
||||||||
net cash provided by operating
activities:
|
||||||||
Depreciation, depletion and
amortization
|
28,480 | 32,269 | ||||||
Accretion
expense
|
29,973 | 25,797 | ||||||
Settlement of asset retirement
obligations
|
||||||||
for plugged and abandoned
wells
|
(18,794 | ) | - | |||||
Increase in
receivables
|
(33,778 | ) | (91,655 | ) | ||||
Decrease in
payables
|
(13,296 | ) | - | |||||
Net
cash provided by operating activities
|
$ | 124,696 | $ | 1,077,641 | ||||
Noncash
investing and financing activities:
|
||||||||
Increase
(decrease) in oil and gas
|
||||||||
properties – Asset retirement
obligations
|
$ | 29,459 | $ | (80,649 | ) |
The
accompanying notes are an integral
part of
these financial statements.
8
Southwest
Oil & Gas Income Fund VII-A, L.P.
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, 2009, and for the three and
nine months ended September 30, 2009, is unaudited. Certain
information and footnote disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted in this Form 10-Q pursuant to the rules and regulations of
the Securities and Exchange Commission. However, in the opinion of management,
these interim financial statements include all the necessary adjustments to
fairly present the results of the interim periods and all such adjustments are
of a normal recurring nature. The interim consolidated financial statements
should be read in conjunction with the Partnership’s Annual Report on Form 10-K
for the year ended December 31, 2008.
3.
Abandonment
Obligations
The
Partnership follows the provisions of ASC topic 410-20, formerly SFAS No. 143,
“Accounting for Asset
Retirement Obligations” (“SFAS 143”). ASC topic 410-20 requires the
Partnership to recognize a liability for the present value of all legal
obligations associated with the retirement of tangible, long-lived assets and
capitalize an equal amount as a cost of the asset. The cost associated
with the abandonment obligations, along with any estimated salvage value, is
included in the computation of depreciation, depletion and
amortization.
Changes
in abandonment obligations for the nine months ended September 30, 2009 and 2008
are as follows:
2009
|
2008
|
|||||||
Beginning
of period
|
$ | 434,589 | $ | 479,794 | ||||
Settlement
of obligations for plugged and abandoned wells
|
(18,794 | ) | - | |||||
Revisions
of estimates
|
29,459 | (80,649 | ) | |||||
Accretion
expense
|
29,973 | 25,797 | ||||||
End
of period
|
$ | 475,227 | $ | 424,942 |
9
Southwest
Oil & Gas Income Fund VII-A, L.P.
Notes
to Financial Statements
4.
Recent Accounting
Pronouncements
Effective
July 1, 2009, the Partnership adopted SFAS No. 168, “The Financial Accounting Standards
Board (“FASB”) Accounting Standards Codification and the Hierarchy of
Generally Accepted Accounting Principles, a replacement of FASB Statement No.
162” (“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards
Codification (“ASC”). SFAS 168 establishes the ASC as the source of
authoritative accounting principles recognized by the FASB to be applied by
nongovernmental entities in the preparation of financial statements in
conformity with GAAP. Other than the manner in which new accounting
guidance is referenced, the adoption did not have a material impact on our
financial statements.
Effective
April 1, 2009, the Partnership adopted SFAS No. 165, “Subsequent Events” (“SFAS
165”) (superseded by ASC topic 855-10-5), which establishes principles and
requirements for disclosure of subsequent events. It establishes the
period after the balance sheet date during which events or transactions are to
be evaluated for potential disclosure. It also establishes the
circumstances under which an entity shall recognize events or transactions
occurring after the balance sheet date. The adoption of SFAS 165 did not have a
material impact on our disclosure of subsequent events.
In
December 2008, the SEC released Final Rule, “Modernization of Oil and Gas
Reporting”. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. The new requirements also will allow companies to
disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (1) report the independence
and qualifications of its reserves preparer or auditor, (2) file reports
when a third party is relied upon to prepare reserves estimates or conducts a
reserves audit, and (3) report oil and gas reserves using an average price
based upon the prior 12-month period rather than year-end prices. The new
disclosure requirements are effective for financial statements for fiscal years
ending on or after December 31, 2009. The effect of adopting the SEC rule
has not been determined, but it is not expected to have a significant effect on
our reported financial position or results of operations.
5.
Subsequent
Events
The
Partnership has evaluated events and transactions that occurred after the
balance sheet date of September 30, 2009 through November 16, 2009, the date the
financial statements were available to be issued. The Partnership did
not have any subsequent events that would require recognition in the financial
statements or disclosures in these notes to the financial
statements.
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 will not
be reinvested in other revenue producing assets except to the extent that
production facilities and wells are improved or reworked or where methods are
employed to improve or enable more efficient recovery of oil and gas
reserves. The economic life of the Partnership thus depends on the
period over which the Partnership’s oil and gas reserves are economically
recoverable.
Increases
or decreases in Partnership revenues and, therefore, distributions to partners
will depend primarily on changes in the prices received for production, changes
in volumes of production sold, increases and decreases in production costs,
enhanced recovery projects, offset drilling activities pursuant to farm-out
arrangements, sales of properties, and the depletion of wells. Since
wells deplete over time, production can generally be expected to decline from
year to year.
Production
costs and general and administrative costs usually decrease with production
declines; however, these costs may not decrease proportionately to production
volumes or revenue. Net income available for distribution to the
partners is therefore expected to decline in later years based on these
factors.
The
Partnership recognizes income from oil and gas properties on an accrual basis
while the quarterly cash distributions are based on a calculation of actual cash
received from oil and gas sales, net of expenses incurred during that quarterly
period. If the calculation results in expenses incurred exceeding the oil and
gas income received during a quarter, no cash distribution is due until the
deficit is recovered from future cash flows.
Oil and Gas
Properties
The
Partnership uses the full cost method of accounting for its oil and gas
producing activities. Accordingly, all costs associated with
acquisition, exploration, and development of oil and gas reserves are
capitalized. Depletion is provided using the unit-of production
method based upon estimates of proved oil and gas reserves. The
amortizable base includes estimated future development costs and dismantlement,
restoration and abandonment costs, net of estimated salvage
value. All of the Partnership’s oil and gas properties are located
within the United States. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
sold.
Should
the net capitalized costs exceed the estimated present value of oil and gas
reserves, discounted at 10%, such excess costs would be charged to current
expense. As of September 30, 2009, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
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”).
Oil and
gas prices have a significant impact on the discounted present value of the
Partnership’s estimated proved oil and gas reserves. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are generally held constant indefinitely. As a result, the
changes in oil and gas prices have a significant impact on the computation of
the ceiling calculation.
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,
|
||||||||
2009
|
2008
|
|||||||
Oil
production in barrels
|
2,609 | 3,826 | ||||||
Gas
production in mcf
|
8,485 | 10,033 | ||||||
Total
(BOE)
|
4,023 | 5,498 | ||||||
Average
price per barrel of oil
|
$ | 65.17 | $ | 115.98 | ||||
Average
price per mcf of gas
|
$ | 5.12 | $ | 10.95 | ||||
Partnership
distributions
|
$ | 85,000 | $ | 435,000 | ||||
Limited
partner distributions
|
$ | 76,500 | $ | 391,500 | ||||
Per
unit distribution to limited partners
|
$ | 5.10 | $ | 26.10 | ||||
Number
of limited partner units
|
15,000 | 15,000 |
Operating
Results
The
following discussion compares our results for the quarters ended September 30,
2009 and 2008. Unless otherwise indicated, references to 2009 and
2008 within this section refer to the respective quarterly period.
Revenues
Comparing
2009 to 2008, oil and gas sales decreased $340,120, of which price variances
accounted for a $182,018 decrease and production variances accounted for a
$158,102 decrease.
Production
in 2009 (on a BOE basis) was 27% lower than 2008. Oil production in
2009 was 32% lower than 2008 due primarily to production decline on one
property. Our gas production in 2009 was 15% lower than 2008 due
primarily to production declines on three properties.
In 2009,
our realized oil price was 44% lower than 2008, while our realized gas price was
53% lower. Historically, the markets for oil and gas have been
volatile, and they are likely to continue to be volatile.
Expenses
Oil and
gas production costs on a BOE basis increased from $19.31 per BOE in 2008 to
$22.65 per BOE in 2009. The increase in oil and gas production costs
was due primarily to volume decline exceeding the production cost
decline.
Depletion
on a BOE basis decreased 3% in 2009. Comparing 2009 to 2008,
depletion expense decreased $2,981, of which rate variances accounted for a $233
decrease and production variances accounted for a $2,748 decrease.
Accretion
expense increased 9% in 2009 due primarily to changes in asset retirement
obligations.
General
and administrative (“G&A”) expenses were 12% higher in 2009 as compared to
2008.
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,
|
||||||||
2009
|
2008
|
|||||||
Oil
production in barrels
|
8,813 | 11,763 | ||||||
Gas
production in mcf
|
29,378 | 32,740 | ||||||
Total
(BOE)
|
13,709 | 17,220 | ||||||
Average
price per barrel of oil
|
$ | 52.10 | $ | 109.77 | ||||
Average
price per mcf of gas
|
$ | 4.50 | $ | 11.11 | ||||
Partnership
distributions
|
$ | 131,513 | $ | 1,086,441 | ||||
Limited
partner distributions
|
$ | 118,356 | $ | 977,806 | ||||
Per
unit distribution to limited partners
|
$ | 7.89 | $ | 65.19 | ||||
Number
of limited partner units
|
15,000 | 15,000 |
Operating
Results
The
following discussion compares our results for the nine months ended September
30, 2009 and 2008. Unless otherwise indicated, references to 2009 and
2008 within this section refer to the respective nine-month period.
Revenues
Comparing
2009 to 2008, oil and gas sales decreased $1,063,716, of which price variances
accounted for a $702,537 decrease and production variances accounted for a
$361,179 decrease.
Production
in 2009 (on a BOE basis) was 20% lower than 2008. Our oil production
in 2009 was 25% lower than 2008 and our gas production was 10% lower in 2009
than 2008 due primarily to production decline on one property.
In 2009,
our realized oil price was 53% lower than 2008, while our realized gas price was
60% lower. Historically, the markets for oil and gas have been
volatile, and they are likely to continue to be volatile.
Expenses
Oil and
gas production costs on a BOE basis decreased from $22.10 per BOE in 2008 to
$21.41 per BOE in 2009. The decrease in oil and gas production costs
was due primarily to lower production taxes resulting from lower oil and gas
revenues.
Depletion
on a BOE basis increased 11% in 2009. Comparing 2009 to 2008,
depletion expense decreased $3,789, of which rate variances accounted for a
$2,789 increase and production variances accounted for a $6,578
decrease.
Accretion
expense increased 16% in 2009 due primarily to changes in asset retirement
obligations.
General
and administrative (“G&A”) expenses were 1% higher in 2009.
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.
14
Liquidity and Capital
Resources
Partnership
distributions during the nine months ending September 30, 2009 were $131,513, of
which $118,356 was distributed to the limited partners and $13,157 to the
general partners. Cumulative cash distributions of $15,963,118 have
been made to the general and limited partners as of September 30,
2009. As of September 30, 2009, $14,384,999 or $959.00 per limited
partner unit has been distributed to the limited partners, representing 192% of
contributed capital.
Recent Accounting
Pronouncements
Effective
July 1, 2009, the Partnership adopted SFAS No. 168, “The Financial Accounting Standards
Board (“FASB”) Accounting Standards Codification and the Hierarchy of Generally
Accepted Accounting Principles, a replacement of FASB Statement No. 162”
(“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards
Codification (“ASC”). SFAS 168 establishes the ASC as the source of
authoritative accounting principles recognized by the FASB to be applied by
nongovernmental entities in the preparation of financial statements in
conformity with GAAP. Other than the manner in which new accounting
guidance is referenced, the adoption did not have a material impact on our
financial statements.
Effective
April 1, 2009, the Partnership adopted SFAS No. 165, “Subsequent Events” (“SFAS
165”) (superseded by ASC topic 855-10-5), which establishes principles and
requirements for disclosure of subsequent events. It establishes the
period after the balance sheet date during which events or transactions are to
be evaluated for potential disclosure. It also establishes the
circumstances under which an entity shall recognize events or transactions
occurring after the balance sheet date. The adoption of SFAS 165 did not have a
material impact on our disclosure of subsequent events.
In
December 2008, the SEC released Final Rule, “Modernization of Oil and Gas
Reporting”. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. The new requirements also will allow companies to
disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (1) report the independence
and qualifications of its reserves preparer or auditor, (2) file reports
when a third party is relied upon to prepare reserves estimates or conducts a
reserves audit, and (3) report oil and gas reserves using an average price
based upon the prior 12-month period rather than year-end prices. The new
disclosure requirements are effective for financial statements for fiscal years
ending on or after December 31, 2009. The effect of adopting the SEC rule
has not been determined, but it is not expected to have a significant effect on
our reported financial position or results of operations.
15
Item
3. Quantitative and Qualitative
Disclosures About Market Risk
The
Partnership financial condition, results of operations, and capital resources
are highly dependent upon the prevailing market prices of, and demand for, oil
and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are
beyond our control. These factors include the level of global demand
for petroleum products, foreign supply of oil and gas, the establishment of and
compliance with production quotas by oil-exporting countries, trading activities
in commodities future markets, weather conditions, the price and availability of
alternative fuels, and overall economic conditions, both foreign and
domestic. The Partnership cannot predict future oil and gas prices
with any degree of certainty. Sustained weakness in oil and gas
prices may adversely affect our financial condition, results of operations and
cash distributions to partners.
The
Partnership is not a party to any derivative or embedded derivative
instruments.
Item
4. Controls and
Procedures
Disclosure Controls and
Procedures
The
Managing General Partner has established disclosure controls and procedures that
are adequate to provide reasonable assurance that management will be able to
collect, process and disclose both financial and non-financial information, on a
timely basis, in the Partnership’s reports to the SEC. Disclosure
controls and procedures include all processes necessary to ensure that material
information is recorded, processed, summarized and reported within the time
periods specified in the SEC’s rules and forms, and is accumulated and
communicated to management, including our chief executive and chief financial
officers, to allow timely decisions regarding required disclosures.
With respect to these disclosure
controls and procedures:
·
|
management
has evaluated the effectiveness of the disclosure controls and procedures
as of the end of the period covered by this
report;
|
·
|
this
evaluation was conducted under the supervision and with the participation
of management, including the chief executive and chief financial officers
of the Managing General Partner;
and
|
·
|
it
is the conclusion of chief executive and chief financial officers of the
Managing General Partner that these disclosure controls and procedures are
effective in ensuring that information that is required to be disclosed by
the Partnership in reports filed or submitted with the SEC is recorded,
processed, summarized and reported within the time periods specified in
the rules and forms established by the
SEC.
|
Internal Control Over
Financial Reporting
There has
not been any change in the Partnership’s internal control over financial
reporting that occurred during the nine months ended September 30, 2009 that has
materially affected, or is reasonably likely to materially affect, its internal
control over financial reporting.
16
PART
II. - OTHER INFORMATION
Item
1.
Legal
Proceedings
None
Item
1A. Risk
Factors
In
evaluating all forward-looking statements, you should specifically consider
various factors that may cause actual results to vary from those contained in
the forward-looking statements. Our risk factors are included in our
Annual Report on Form 10-K for the year ended December 31, 2008, as
filed with the U.S. Securities and Exchange Commission on March 27, 2009 and
available at www.sec.gov. Following are additional risk factors that
could affect our financial performance or could cause actual results to differ
materially from estimates contained in our forward-looking
statements.
Certain
U.S. federal income tax deductions currently available with respect to oil and
gas exploration and development may be eliminated as a result of future
legislation.
The
Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if
enacted into law, make significant changes to United States tax laws, including
the elimination of certain key U.S. federal income tax incentives currently
available to oil and natural gas exploration and production companies. These
changes include, but are not limited to: (1) the repeal of the
percentage depletion allowance for oil and natural gas properties, (2) the
elimination of current deductions for intangible drilling and development costs,
(3) the elimination of the deduction for certain domestic production activities,
and (4) an extension of the amortization period for certain geological and
geophysical expenditures. It is unclear whether any such changes will be enacted
or how soon any such changes could become effective. The passage of
any legislation as a result of these proposals or any other similar changes in
U.S. federal income tax laws could eliminate certain tax deductions that
are currently available with respect to oil and gas exploration and development,
and any such change could negatively affect our financial condition and results
of operations.
The
adoption of climate change legislation by Congress could result in increased
operating costs and reduced demand for the oil and natural gas we
produce.
On June
26, 2009, the U.S. House of Representatives approved adoption of the “American
Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey
cap-and-trade legislation” or ACESA. The purpose of ACESA is to
control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United
States. GHGs are certain gases, including carbon dioxide and methane,
that may be contributing to warming of the Earth’s atmosphere and other climatic
changes. ACESA would establish an economy-wide cap on emissions of
GHGs in the United States and would require an overall reduction in GHG
emissions of 17% (from 2005 levels) by 2020, and by over 80% by
2050. Under ACESA, most sources of GHG emissions would be required to
obtain GHG emission “allowances” corresponding to their annual emissions of
GHGs. The number of emission allowances issued each year would
decline as necessary to meet ACESA’s overall emission reduction
goals. As the number of GHG emission allowances declines each year,
the cost or value of allowances is expected to escalate
significantly. The net effect of ACESA will be to impose increasing
costs on the combustion of carbon-based fuels such as oil, refined petroleum
products, and natural gas.
The U.S.
Senate has begun work on its own legislation for controlling and reducing
emissions of GHGs in the United States. If the Senate adopts GHG
legislation that is different from ACESA, the Senate legislation would need to
be reconciled with ACESA and both chambers would be required to approve
identical legislation before it could become law. President Obama has
indicated that he is in support of the adoption of legislation to control and
reduce emissions of GHGs through an emission allowance permitting system that
results in fewer allowances being issued each year but that allows parties to
buy, sell and trade allowances as needed to fulfill their GHG emission
obligations. Although it is not possible at this time to predict
whether or when the Senate may act on climate change legislation or how any bill
approved by the Senate would be reconciled with ACESA, any laws or regulations
that may be adopted to restrict or reduce emissions of GHGs would likely require
us to incur increased operating costs, and could have an adverse effect on
demand for the oil and natural gas we produce.
17
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
|
18
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
16, 2009
|
19