Page 24 of 24
FORM 10-Q/A
AMENDMENT NO. 1
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 March 31, 2003
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 33-47667-01
SOUTHWEST OIL & GAS 1992-93 INCOME PROGRAM
Southwest Oil & Gas Income Fund XI-A, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2427267
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
Midland, Texas 79701
(Address of principal executive offices)
(432) 686-9927
(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 No_X_
The total number of pages contained in this report is 24.
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, 2002, which are found in the Registrant's Form
10-K/A Report for 2002 filed with the Securities and Exchange Commission.
The December 31, 2002 balance sheet included herein has been taken from the
Registrant's 2002 Form 10-K/A Report. Operating results for the three
month period ended March 31, 2003 are not necessarily indicative of the
results that may be expected for the full year.
Introductory Note - Statement of Financial Accounting Standard No. 143
The Partnership implemented SFAS No. 143 effective January 1, 2003 (See
Note 3) to the Partnership's financial statements. Subsequent to the
filing of the Partnership's Quarterly Report on Form 10-Q, the Partnership
discovered an omission in the calculation of the asset retirement liability
and therefore has restated it's unaudited condensed financial statements
for the period ended March 31, 2003 as described in Note 5 to the
Partnership's financial statements.
Introductory Note - Depletion Method
During the fourth quarter of 2002, the Partnership changed its method of
providing for depletion from the units-of-revenue method to the units-of-
production method as described in Notes 4 and 6 to the Partnership's
financial statements.
This change in depletion method was applied as a cumulative effect of a
change in accounting principle effective as of January 1, 2002. The
unaudited condensed financial statements of the Partnership for the period
ended March 31, 2002, included herein, have been restated (as described in
Notes 4 and 6 to the Partnership's financial statements) using the new
depletion method and differ from those previously issued in the
Partnership's Quarterly Report on Form 10-Q for the period ended March 31,
2002.
Southwest Oil & Gas Income Fund XI-A, L.P.
Balance Sheets
March December
31, 31,
2003 2002
(Restate
d)
---- ----
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 23,653 17,179
Receivable from Managing 31,663 24,291
General Partner
-------- --------
----- -----
Total current assets 55,316 41,470
-------- --------
----- -----
Oil and gas properties -
using the full-
cost method of accounting 1,087,24 1,053,59
8 6
Less accumulated
depreciation,
depletion and 819,236 838,555
amortization
-------- --------
----- -----
Net oil and gas 268,012 215,041
properties
-------- --------
----- -----
$ 323,328 256,511
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability:
Distribution payable $ - 46
-------- --------
----- -----
Other long term liabilities 64,970 -
-------- --------
----- -----
Partners' equity:
General partners (3,350) (4,038)
Limited partners 261,708 260,503
-------- --------
----- -----
Total partners' equity 258,358 256,465
-------- --------
----- -----
$ 323,328 256,511
======= =======
Southwest Oil & Gas Income Fund XI-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2003 2002
(Restate (Restate
d) d)
----- -----
Revenues
- ------------
Oil and gas $ 62,391 33,034
Interest 34 24
-------- --------
- -
62,425 33,058
-------- --------
- -
Expenses
- ------------
Production 26,712 14,238
General and administrative 4,320 4,196
Depreciation, depletion and 5,000 6,000
amortization
Accretion 1,274 -
-------- --------
- -
37,306 24,434
-------- --------
- -
Net income before cumulative 25,119 8,624
effect
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See (5,725) -
Note 3
Cumulative effect of change in
accounting principle
- change in depletion method - - 1,000
See Note 4
-------- --------
- -
Net income $ 19,394 9,624
===== =====
Net income allocated to:
Managing General Partner $ 2,195 1,316
===== =====
General partner $ 244 146
===== =====
Limited partners $ 16,955 8,162
===== =====
Per limited partner unit $ 7.84
before cumulative effect 2.54
Cumulative effects per (1.83) .35
limited partner unit
-------- --------
- -
Per limited partner unit $ 6.01
2.89
===== =====
Pro forma amounts assuming
changes are applied
retroactively (See Note 3):
Net income before cumulative $ - 7,191
effect
===== =====
Per limited partner unit $ - 2.08
(2,821.0)
===== =====
Net income $ - 8,191
===== =====
Per limited partner unit $ - 2.43
(2,821.0)
===== =====
Southwest Oil & Gas Income Fund XI-A, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2003 2002
(Restate (Restate
d) d)
----- -----
Cash flows from operating
activities:
Cash received from oil and gas $ 49,667 35,379
sales
Cash paid to suppliers (25,681) (35,439)
Interest received 34 24
-------- --------
- -
Net cash provided by (used in) 24,020 (36)
operating activities
-------- --------
- -
Cash flows provided by investing
activities:
Sale of oil and gas properties - 1,047
-------- --------
- -
Cash flows used in financing
activities:
Distributions to partners (17,546) (6,023)
-------- --------
- -
Net increase (decrease) in cash 6,474 (5,012)
and cash equivalents
Beginning of period 17,179 13,139
-------- --------
- -
End of period $ 23,653 8,127
===== =====
Reconciliation of net income to
net cash
provided by (used in) operating
activities:
Net income $ 19,394 9,624
Adjustments to reconcile net
income to net
cash provided by (used in)
operating activities:
Depreciation, depletion and 5,000 6,000
amortization
Accretion 1,274 -
Cumulative effect of change in
accounting
principle - SFAS No. 143 5,725 -
Cumulative effect of change in
accounting
principle - change in depletion - (1,000)
method
(Increase) decrease in (12,724) 2,345
receivables
Increase (decrease) increase in 5,351 (17,005)
payables
-------- --------
- -
Net cash provided by (used in) $ 24,020 (36)
operating activities
===== =====
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption
of SFAS No.143 $ 57,971 -
====== ======
Southwest Oil & Gas Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Oil & Gas Income Fund XI-A, L.P. was organized under the
laws of the state of Delaware on May 5, 1992, 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 will sell 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. serves as the Managing General Partner and H. H. Wommack, III, as
the individual general partner. Partnership profits and losses, as
well as all items of income, gain, loss, deduction, or credit, will be
credited or charged as follows:
Limited General
Partners Partners
(1)
-------- --------
Organization and 100% -
offering expenses (2)
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs 90% 10%
(3)
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned
on capital
contributions 100% -
Oil and gas revenues 90% 10%
Other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to the Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
Southwest Oil & Gas Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
The interim financial information as of March 31, 2003, and for the
three months ended March 31, 2003, 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/A 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/A for the year ended December 31, 2002.
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 $57,971, a long term liability of
approximately $63,696 and a loss of approximately $5,725 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 March 31,
2003, the asset retirement obligation was $64,970, and the increase in
the balance from January 1, 2003 of $1,274 is due to accretion
expense. The pro forma amounts for the three months ended March 31,
2002, which are presented on the face of the statements of operations,
reflect the effect of retroactive application of SFAS No. 143.
4. Cumulative effect of change in accounting principle - change in
depletion method
In the fourth quarter of 2002, the Partnership changed methods of
accounting for depletion of capitalized costs from the units-of-
revenue method to the units-of-production method. The newly adopted
accounting principle is preferable in the circumstances because the
units-of-production method results in a better matching of the costs
of oil and gas production against the related revenue received in
periods of volatile prices for production as have been experienced in
recent periods. Additionally, the units-of-production method is the
predominant method used by full cost companies in the oil and gas
industry, accordingly, the change improves the comparability of the
Partnership's financial statements with its peer group. The
Partnership adopted the units-of-production method through the
recording of a cumulative effect of a change in accounting principle
in the amount of $1,000 effective as of January 1, 2002. The
Partnership's depletion for the three months ended March 31, 2003 and
2002 has been calculated using the units-of-production method. The
effect of the change on the three months ended March 31, 2002 was to
decrease income before cumulative effect of a change in accounting
principle by $2,000 ($.71 per limited partner unit) and net income by
$1,000 ($.35 per limited partner unit).
Southwest Oil & Gas Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
5. March 31, 2003 Restatement
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143 as described in Note 3.
Subsequent to the issuance of the Partnership's Quarterly Report on
Form 10-Q for the three months ended March 31, 2003, the Partnership
determined that it did not properly discount the estimated future
plugging liability to its present value.
This change in the calculation used to determine the amount of the
Partnership's asset retirement liability under SFAS No. 143 resulted
in a decrease in the Partnership's previously reported other long term
liability of $72,252 from $137,222 to $64,970 as of March 31, 2003 and
did not effect the Partnership's 2003 cash flows from operations,
investing or financing activities.
The change had the following effects on the Statement of Operations
for the three months ended March 31, 2003. (Periods prior to 2003
were not affected by the change).
Restated Previously
Reported
Accretion $1,274 2,691
Income before cumulative effect 25,119 23,702
Cumulative effect of change in (5,725) (89,767)
accounting principle
Net income (loss) 19,394 (66,065)
Net income (loss) allocated
to:
Managing General Partner 2,195 (3,308)
General partner 244 (368)
Limited partners 16,955 (62,389)
Income (loss) per limited
partner unit before
cumulative effect 7.84 (22.12)
Cumulative effect per (1.83) -
limited partner unit
Net income (loss) per 6.01 (22.12)
limited partner unit
Southwest Oil & Gas Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
6. March 31, 2002 Restatement
During the fourth quarter of 2002, the Partnership changed its method
of providing for depletion from the units-of-revenue method to the
units-of-production method as described in Note 4.
Subsequent to the issuance of the Partnership's Quarterly Report on
Form 10-Q for the three months ended March 31, 2003, the Partnership
determined that the above change in accounting method should have been
adopted by the Partnership as a cumulative effect of a change in
accounting principle effective as of January 1, 2002. The Partnership
had previously applied the change in the method of providing for
depletion prospectively as of October 1, 2002.
This change in the method used to implement the Partnership's change
in the manner in which it determines depletion resulted in a decrease
in the Partnership's previously reported net oil and gas properties of
$1,000 from $216,041 to $215,041 as of December 31, 2002 and did not
effect the Partnership's 2002 cash flows from operations, investing or
financing activities.
The change had the following effects on the Statement of Operations
for the three months ended March 31, 2002.
Restated Previously
Reported
Depreciation, depletion and $6,000 4,000
amortization
Income (loss) before cumulative 8,624 10,624
effect
Cumulative effect of change in 1,000 -
accounting principle
Net income (loss) 9,624 10,624
Net income (loss) allocated
to:
Managing General Partner 1,316 1,316
General partner 146 146
Limited partners 8,162 9,162
Income (loss) per limited
partner unit before
cumulative effect 2.54 3.25
Cumulative effect per .35 -
limited partner unit
Net income (loss) per 2.89 3.25
limited partner unit
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Oil & Gas Income Fund XI-A, L.P. was organized as a Delaware
limited partnership on May 5, 1992. The offering of such limited
partnership interests began August 20, 1992 as part of a shelf offering
registered under the name Southwest Oil & Gas 1992-93 Income Program.
Minimum capital requirements for the Partnership were met on March 17,
1993, with the offering of limited partnership interests concluding April
30, 1993. At the conclusion of the offering of limited partnership
interests, 122 limited partners had purchased 2,821 units for $1,410,500.
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, lease
operating expenses, enhanced recovery projects, offset drilling activities
pursuant to farmout 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 fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing no workovers
during 2003 to enhance production. Additional workovers may be performed
in the year 2004. The partnership may have an increase in production
volumes for the year 2004, otherwise, the partnership will most likely
experience the historical production decline, which has approximated 9% per
year.
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.
In the fourth quarter of 2002, the Partnership changed methods of
accounting for depletion of capitalized costs from the units-of-revenue
method to the units-of-production method. The newly adopted accounting
principle is preferable in the circumstances because the units-of-
production method results in a better matching of the costs of oil and gas
production against the related revenue received in periods of volatile
prices for production as have been experienced in recent periods.
Additionally, the units-of-production method is the predominant method used
by full cost companies in the oil and gas industry, accordingly, the change
improves the comparability of the Partnership's financial statements with
its peer group. The effect of this change in method was to increase
depletion expense for the three months ended March 31, 2002 by $2,000 and
decrease net income for the three months ended March 31, 2002 by $1,000.
See Note 4 of the notes to the Partnership's financial statements.
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 March 31, 2003, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
Critical Accounting Policies
Full cost ceiling calculations 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 on an annual basis 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.
In the fourth quarter of 2002, the Partnership changed methods of
accounting for depletion of capitalized costs from the units-of-revenue
method to the units-of-production method. The newly adopted accounting
principle is preferable in the circumstances because the units-of-
production method results in a better matching of the costs of oil and gas
production against the related revenue received in periods of volatile
prices for production as have been experienced in recent periods.
Additionally, the units-of-production method is the predominant method used
by full cost companies in the oil and gas industry, accordingly, the change
improves the comparability of the Partnership's financial statements with
its peer group. The effect of this change in method was to increase
depletion expense for the three months ended March 31, 2002 by $2,000 and
decrease net income for the three months ended March 31, 2002 by $1,000.
Results of Operations
A. General Comparison of the Quarters Ended March 31, 2003 and 2002
The following table provides certain information regarding performance
factors for the quarters ended March 31, 2003 and 2002.
Three Months
Ended Percenta
ge
March 31, Increase
2003 2002 (Decreas
e)
---- ---- --------
--
Average price per $ 32.11 66%
barrel of oil 19.36
Average price per mcf $ 5.32 186%
of gas 1.86
Oil production in 900 900 -
barrels
Gas production in mcf 6,300 8,400 (25%)
Gross oil and gas $ 62,391 33,034 89%
revenue
Net oil and gas revenue $ 35,679 18,796 90%
Partnership $ 17,500 6,000 192%
distributions
Limited partner $ 15,750 5,400 192%
distributions
Per unit distribution
to limited
partners $ 5.58 192%
1.91
Number of limited 2,821 2,821
partner units
Revenues
The Partnership's oil and gas revenues increased to $62,391 from $33,034
for the quarters ended March 31, 2003 and 2002, respectively, an increase
of 89%. The principal factors affecting the comparison of the quarters
ended March 31, 2003 and 2002 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended March 31, 2003 as compared to the
quarter ended March 31, 2002 by 66%, or $12.75 per barrel, resulting in
an increase of approximately $11,500 in revenues. Oil sales
represented 46% of total oil and gas sales during the quarter ended
March 31, 2003 as compared to 53% during the quarter ended March 31,
2002.
The average price for an mcf of gas received by the Partnership
increased during the same period by 186%, or $3.46 per mcf, resulting
in an increase of approximately $21,800 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $33,300. 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 remained unchanged during the quarter ended March 31,
2003 as compared to the quarter ended March 31, 2002.
Gas production decreased approximately 2,100 mcf or 25% during the same
period, resulting in a decrease of approximately $3,900 in income from
net profits interests.
The total decrease in revenues due to the change in production is
approximately $3,900. The decrease in gas production is primarily due
to one lease, which the wells were shut in during 2002, and production
is being slowly brought back on.
Costs and Expenses
Total costs and expenses increased to $37,306 from $24,434 for the quarters
ended March 31, 2003 and 2002, respectively, an increase of 53%. The
increase is a direct result of the accretion expense associated with our
long term liability related to expected abandonment costs of our oil and
natural gas properties, lease operating costs, general and administrative
expense.
1. Lease operating costs and production taxes were 88% higher, or
approximately $12,500 more during the quarter ended March 31, 2003 as
compared to the quarter ended March 31, 2002. The increase in lease
operating expense and production taxes is due primarily to repairs and
maintenance on several leases, and the increase in production taxes in
relation to the increase in gross revenues received in 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 3%
or approximately $100 during the quarter ended March 31, 2003 as
compared to the quarter ended March 31, 2002.
3. Depletion expense decreased to $5,000 for the quarter ended March 31,
2003 from $6,000 for the same period in 2002. This represents a
decrease of 17%. In the fourth quarter of 2002, the Partnership
changed methods of accounting for depletion of capitalized costs from
the units-of-revenue method to the units-of-production method. The
newly adopted accounting principle is preferable in the circumstances
because the units-of-production method results in a better matching of
the costs of oil and gas production against the related revenue
received in periods of volatile prices for production as have been
experienced in recent periods. Additionally, the units-of-production
method is the predominant method used by full cost companies in the oil
and gas industry, accordingly, the change improves the comparability of
the Partnership's financial statements with its peer group. The effect
of this change in method was to increase depletion expense for the
three months ended March 31, 2002 by $2,000 and decrease net income for
the three months ended March 31, 2002 by $1,000. The contributing
factor to the decrease in depletion expense is in relation to the BOE
depletion rate for the quarter ended March 31, 2003, which was $2.56
applied to 1,950 BOE as compared to $2.61 applied to 2,300 BOE for the
same period.
Cumulative effect of change in accounting principle
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 $57,971, a long term liability of
approximately $63,696 and a loss of approximately $5,725 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 March 31, 2003, the asset retirement obligation
was $64,970, and the increase in the balance from January 1, 2003 of $1,274
is due to accretion expense. The pro forma amounts for the three months
ended March 31, 2002, which are presented on the face of the statements of
operations, reflect the effect of retroactive application of SFAS No. 143.
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 (used in) operating activities were approximately
$24,000 in the quarter ended March 31, 2003 as compared to approximately
$(36) in the quarter ended March 31, 2002. The primary source of cash
flows from operating activities was profitable operations.
There were not cash flows provided by investing activities in the quarter
ended March 31, 2003. Cash flows provided by investing activities were
approximately $1,000 in the quarter ended March 31, 2002.
Cash flows used in financing activities were $17,500 in the quarter ended
March 31, 2003 as compared to $6,000 in the quarter ended March 31, 2002.
The only use in financing activities was the distributions to partners.
Total distributions during the quarter ended March 31, 2003 were $17,500 of
which $15,750 was distributed to the limited partners and $1,750 to the
general partners. The per unit distribution to limited partners during the
quarter ended March 31, 2003 was $5.58. Total distributions during the
quarter ended March 31, 2002 were $6,000 of which $5,400 was distributed to
the limited partners and $600 to the general partners. The per unit
distribution to limited partners during the quarter ended March 31, 2002
was $1.91.
The sources for the 2003 distributions of $17,500 were oil and gas
operations of approximately $24,000, resulting in excess cash for
contingencies or subsequent distributions to partners. The sources for the
2002 distributions of $6,000 were net of oil and gas operations of
approximately $(36) and the change of oil and gas properties of
approximately $1,000, with the balance from available cash on hand at the
beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,285,417 have been made to the partners. As of March 31, 2003,
$1,170,045 or $414.76 per limited partner unit has been distributed to the
limited partners, representing a 83% return of the capital contributed.
As of March 31, 2003, the Partnership had approximately $55,300 in working
capital. The Managing General Partner knows of no unusual contractual
commitments. Although the partnership held many long-lived properties at
inception, because of the restrictions on property development imposed by
the partnership agreement, the Partnership cannot develop its non producing
properties, if any. 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.
The Managing General Partner has examined various alternatives to address
the issue of depleting producing reserves. Continuing operations exposes
the partnership to an inevitable decline in operating results and
distributions of cash. Liquidating the partnership would result in
immediate realization of cash for limited partners, but prices paid by
purchasers of Partnership property in liquidation would likely include a
substantial discount for risks and uncertainties of future cash flows, as
well as any development risks. After reviewing various alternatives, we
initiated a plan to merge the Partnership and 20 other limited partnerships
with and into the Managing General Partner. On October 17, 2002, the
Managing General Partner filed a Registration Statement on form S-4 with
the Securities and Exchange Commission relating to this proposed merger.
There is no assurance, however, that this merger will be consummated.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
approximately $124.0 million of principal due between December 31, 2002 and
December 31, 2004. The Managing General Partner is constantly monitoring
its cash position and its ability to meet its financial obligations as they
become due, and in this effort, is continually exploring various strategies
for addressing its current and future liquidity needs. The Managing
General Partner regularly pursues and evaluates recapitalization strategies
and acquisition opportunities (including opportunities to engage in
mergers, consolidations or other business combinations) and at any given
time may be in various stages of evaluating such opportunities.
Based on current production, commodity prices and cash flow from
operations, the Managing General Partner has adequate cash flow to fund
debt service, developmental projects and day to day operations, but it is
not sufficient to build a cash balance which would allow the Managing
General Partner to meet its debt principal maturities scheduled for 2004.
Therefore the Managing General Partner is currently seeking to renegotiate
the terms of its obligations, including extending maturity dates, or to
engage new lenders or equity investors in order to satisfy its financial
obligations maturing in 2004.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful. In the event these efforts are
unsuccessful, the Managing General Partner would need to look to other
alternatives to meet its debt obligations, including potentially selling
its assets. There can be no assurance, however, that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Please see the Partnership's Quarterly Report on Form 10-
Q for the quarterly period ended September 30, 2003, which will be filed
with the Commission on or before November 14, 2003, for updated information
on the liquidity of the Managing General Partner. The liquidity of the
Managing General Partner, however, does not have a material impact on the
operations of the Partnership. The partnership agreement of the
Partnership allows the limited partners to elect a successor managing
general partner to continue Partnership operations.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged. This statement has been adopted by the Partnership effective
January 1, 2003. The transition adjustment resulting from the adoption of
SFAS No. 143 has been reported as a cumulative effect of a change in
accounting principle.
In April 2003, the FASB issued Statement of Financial Accounting Standards
No. 149, Amendment of Statement No. 133 on Derivative Instruments and
Hedging Activities ("SFAS No. 149"). SFAS No. 149 amendments require that
contracts with comparable characteristics be accounted for similarly,
clarifies when a contract with an initial investment meets the
characteristic of a derivative and clarifies when a derivative requires
special reporting in the statement of cash flows. SFAS No. 149 is
effective for hedging relationships designated and for contracts entered
into or modified after June 30, 2003, except for provisions that relate to
SFAS No. 133 Statement Implementation Issues that have been effective for
fiscal quarters prior to June 15, 2003, should be applied in accordance
with their respective effective dates and certain provisions relating to
forward purchases or sales of when-issued securities or other securities
that do not yet exist, should be applied to existing contracts as well as
new contracts entered into after June 30, 2003. Assessment by the Managing
General Partner revealed this pronouncement to have no impact on the
partnership.
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
(a) Evaluation of Disclosure Controls and Procedures. The chief executive
officer and chief financial officer of the Partnership's managing general
partner have evaluated the effectiveness of the design and operation of the
Partnership's disclosure controls and procedures (as defined in Exchange
Act Rule 13a-14(c)) as of a date within 90 days of the filing date of this
quarterly report. Based on that evaluation, the chief executive officer and
chief financial officer have concluded that the Partnership's disclosure
controls and procedures are effective to ensure that material information
relating to the Partnership and the Partnership's consolidated subsidiaries
is made known to such officers by others within these entities,
particularly during the period this quarterly report was prepared, in order
to allow timely decisions regarding required disclosure.
(b) Changes in Internal Controls. There have not been any significant
changes in the Partnership's internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation.
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:
99.1 Certification pursuant to 18 U.S.C. Section 1350
99.2 Certification pursuant to 18 U.S.C. Section 1350
(b) Reports on Form 8-K:
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 XI-A, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
---------------------------------------
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: November 12, 2003
CERTIFICATIONS
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form
10-Q/A of Southwest Oil
& Gas Income Fund XI-A, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly report;
3. Based on my knowledge, the financial statements,
and other financial
information included in this quarterly 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
quarterly report;
4. The registrant's other certifying officers and I
are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures 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 quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's
disclosure controls
and procedures as of a date within 90 days prior
to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I
have disclosed, based
on our most recent evaluation, 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 in the design or
operation of internal
controls which could adversely affect the
registrant's ability to record,
process, summarize and report financial data and
have identified for the
registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves
management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I
have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 12, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund XI-A, L.P.
CERTIFICATIONS
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form
10-Q/A of Southwest Oil
& Gas Income Fund XI-A, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly report;
3. Based on my knowledge, the financial statements,
and other financial
information included in this quarterly 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
quarterly report;
4. The registrant's other certifying officers and I are
responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures 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 quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's
disclosure controls
and procedures as of a date within 90 days prior to
the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based
on our most recent evaluation, 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 in the design or
operation of internal
controls which could adversely affect the registrant's
ability to record,
process, summarize and report financial data and
have identified for the
registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves
management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers
and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 12, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund XI-A, L.P.
CERTIFICATION PURSUANT TO
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 XI-A, Limited Partnership (the "Company") on Form 10-Q/A for the
period ending March 31, 2003 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, H.H. Wommack, III, 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 12, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund XI-A, L.P.
CERTIFICATION PURSUANT TO
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 XI-A, Limited Partnership (the "Company") on Form 10-Q/A for the
period ending March 31 2003 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, Bill E. Coggin, 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 12, 2003
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund XI-A, L.P.