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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[x] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2004
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number 0-18397
Southwest Oil & Gas Income Fund IX-A, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)
Delaware 75-2274632
(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)
Registrant's telephone number, including area code (432) 682-6324
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
limited partnership interests
Indicate by check mark whether registrant (1) has filed reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days: Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [x]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
Table of Contents
Item Page
Glossary of Oil and Gas Terms 3
Part I
1. Business 5
2. Properties 8
3. Legal Proceedings 9
4. Submission of Matters to a Vote of Security Holders 9
Part II
5. Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities 10
6. Selected Financial Data 11
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 12
7A. Quantitative and Qualitative Disclosures About Market Risk 18
8. Financial Statements and Supplementary Data 19
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 34
9A. Controls and Procedures 34
9B. Other Information 34
Part III
10. Directors and Executive Officers of the Registrant 35
11. Executive Compensation 35
12. Security Ownership of Certain Beneficial Owners and Management 36
13. Certain Relationships and Related Transactions 36
14. Principal Accounting Fees and Services 36
Part IV
15. Exhibits and Financial Statement Schedules 37
Signatures 38
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 (1) 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.
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 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.
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
Item 1. Business
General
Southwest Oil & Gas Income Fund IX-A, L.P. (the "Partnership" or
"Registrant") was organized as a Delaware limited partnership on March 9,
1989. The offering of limited partnership interests began May 11, 1989,
reached minimum capital requirements on October 25, 1989 and concluded
March 31, 1990. The Partnership has no subsidiaries. The Managing General
Partner of the Partnership is Southwest Royalties, Inc. (the "Managing
General Partner"), a Delaware corporation.
The Partnership has expended its capital and acquired interests in
producing oil and gas properties. After such acquisitions, the Partnership
has produced and marketed the crude oil and natural gas produced from such
properties. In most cases, the Partnership purchased working interests in
oil and gas properties, with an occasional purchase of a royalty or
overriding royalty interest. The Partnership purchased either all or part
of the rights and obligations under various oil and gas leases.
During 2004, the Managing General Partner was acquired by Clayton Williams
Energy, Inc. ("CWEI"), a Delaware corporation, and is now a wholly owned
subsidiary of CWEI. CWEI is an oil and gas company based in Midland,
Texas, and its common stock is traded on the Nasdaq Stock Market's National
Market under the symbol "CWEI". All of the directors and executive
officers of the Managing General Partner are employees of CWEI. CWEI
maintains an internet website at www.claytonwilliams.com from which public
information about CWEI may be obtained.
The principal executive offices of the Partnership are located at 6 Desta
Drive, Suite 6500, Midland, Texas, 79705. The Managing General Partner and
its staff, together with certain independent consultants used on an "as
needed" basis, perform various services on behalf of the Partnership,
including the selection of oil and gas properties and the marketing of
production from such properties. The Partnership has no employees.
Operations
The business objective of the Partnership is to maximize the production and
related net cash flow from the properties it currently owns without
engaging in the drilling of any development or exploratory wells except
through farm-out arrangements. If additional drilling is necessary to
fully develop a Partnership property, the Partnership will enter into a
farmout agreement with the Managing General Partner to assign a portion of
the Partnership's interest in the property to the Managing General Partner
in exchange for retaining an interest in the one or more new wells at no
cost to the Partnership. The Managing General Partner obtains a fairness
opinion from an unaffiliated petroleum engineer with respect to the terms
of each farmout agreement with the Partnership.
Principal Products, Marketing and Distribution
The Partnership has acquired and holds working interests in oil and gas
properties located in Texas and New Mexico. All activities of the
Partnership are confined to the continental United States. During 2004,
66% of the Partnership's revenues were derived from the sale of oil
production and 34% were derived from gas production. All oil and gas
produced from these properties is sold to unrelated third parties in the
oil and gas business. The Partnership believes that the loss of any of its
purchasers would not have a material adverse affect on its results of
operations due to the availability of other purchasers.
The revenues generated from the Partnership's oil and gas activities are
dependent upon the current market for oil and gas. The prices received by
the Partnership for its oil and gas production depend upon numerous factors
beyond the Partnership's control, including competition, economic,
political and regulatory developments and competitive energy sources. The
Partnership is unable to accurately predict future prices of oil and
natural gas.
Competition
Because the Partnership has utilized all of its funds available for the
acquisition of interests in producing oil and gas properties, it is not
subject to competition from other oil and gas property purchasers. See
Item 2, Properties.
Factors that may adversely affect the Partnership include delays in
completing arrangements for the sale of production, availability of a
market for production, rising operating costs of producing oil and gas and
complying with applicable water and air pollution control statutes,
increasing costs and difficulties of transportation, and marketing of
competitive fuels. Moreover, domestic oil and gas must compete with
imported oil and gas and with coal, atomic energy, hydroelectric power and
other forms of energy.
Regulation
The Partnership's oil and gas production and related operations are subject
to extensive rules and regulations promulgated by federal, state and local
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Partnership's cost of doing business and affects the
Partnership's profitability. Because such rules and regulations are
frequently amended or reinterpreted, the Partnership is unable to predict
the future cost or impact of complying with such laws.
All of the states in which the Partnership conducts business generally
require permits for drilling operations, drilling bonds and reports
concerning operations and impose other requirements relating to the
exploration and production of oil and gas. Such states also have statutes
or regulations addressing conservation matters, including provisions for
the unitization or pooling of oil and gas properties, the establishment of
maximum rates of production from oil and gas wells and the spacing,
plugging and abandonment of such wells. The statutes and regulations of
certain states also limit the rate at which oil and gas can be produced
from the Partnership's properties.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions, which affect the
marketing of gas produced by the Partnership, as well as the revenues the
Partnership receives for sales of such production. Since the mid-1980s,
the FERC has issued various orders that have significantly altered the
marketing and transportation of gas. These orders resulted in a
fundamental restructuring of interstate pipeline sales and transportation
services, including the unbundling by interstate pipelines of the sales,
transportation, storage and other components of the city-gate sales
services such pipelines previously performed. These FERC actions were
designed to increase competition within all phases of the gas industry.
The interstate regulatory framework may enhance the Partnership's ability
to market and transport its gas, although this framework may also subject
the Partnership to competition and to the more restrictive pipeline
imbalance tolerances and greater associated penalties for violation of such
tolerances.
The Partnership's sales of oil production are not presently regulated and
are made at market prices. The price the Partnership receives from the
sale of those products is affected by the cost of transporting the products
to market. The FERC has implemented regulations establishing an indexing
system for transportation rates for oil pipelines, which, generally, would
index such rates to inflation, subject to certain conditions and
limitations. The Partnership is not able to predict with any certainty
what effect, if any, these regulations will have on the Partnership, but,
other factors being equal, the regulations may, over time, tend to increase
transportation costs which may have the effect of reducing wellhead prices
for oil and natural gas liquids.
Environmental Matters
The Partnership's operations pertaining to oil and gas production and
related activities are subject to numerous and constantly changing federal,
state and local laws governing the discharge of materials into the
environment or otherwise relating to environmental protection. These laws
and regulations may require the acquisition of certain permits prior to or
in connection with drilling activities, restrict or prohibit the types,
quantities and concentration of substances that can be released into the
environment in connection with drilling and production, restrict or
prohibit drilling activities that could impact wetlands, endangered or
threatened species or other protected areas or natural resources, require
some degree of remedial action to mitigate pollution from former
operations, such as pit cleanups and plugging abandoned wells, and impose
substantial liabilities for pollution resulting from the Partnership's
operations. Such laws and regulations may substantially increase the cost
of developing, producing or processing oil and gas and may prevent or delay
the commencement or continuation of a given project and thus generally
could have a material adverse effect upon the Partnership's cash flow and
earnings. The Partnership believes that it is in substantial compliance
with current applicable environmental laws and regulations, and the cost of
compliance with such laws and regulations has not been material and is not
expected to be material during 2005. Nevertheless, changes in existing
environmental laws and regulations or in the interpretations thereof could
have a significant impact on the Partnership's operations, as well as the
oil and gas industry in general. For instance, legislation has been
proposed in Congress from time to time that would reclassify certain oil
and gas production wastes as "hazardous wastes," which reclassification
would make exploration and production wastes subject to much more stringent
handling, disposal and clean-up requirements. State initiatives to further
regulate the disposal of oil and gas wastes and naturally occurring
radioactive materials, if adopted, could have a similar impact on the
Partnership.
The United States Oil Pollution Act of 1990 ("OPA `90"), and similar
legislation enacted in Texas, Louisiana and other coastal states, addresses
oil spill prevention and control and significantly expands liability
exposure across all segments of the oil and gas industry. OPA `90 and such
similar legislation and related regulations impose on us a variety of
obligations related to the prevention of oil spills and liability for
damages resulting from such spills. OPA `90 imposes strict and, with
limited exceptions, joint and several liabilities upon each responsible
party for oil removal costs and a variety of public and private damages.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes
of persons that are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the
owner or operator of the disposal site or the site where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances at the site where the release occurred. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon
for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous
substances released into the environment. The failure of an operator of a
property owned by the Partnership to comply with applicable environmental
regulations may, in certain circumstances, be attributed to the
Partnership. The Partnership does not believe that it will be required to
incur any material expenditures to comply with existing environmental
requirements.
The Resource Conservation and Recovery Act ("RCRA"), and analogous state
laws govern the handling and disposal of hazardous and solid wastes. Wastes
that are classified as hazardous under RCRA are subject to stringent
handling, recordkeeping, disposal and reporting requirements. RCRA
specifically excludes from the definition of hazardous waste "drilling
fluids, produced waters, and other wastes associated with the exploration,
development, or production of crude oil, natural gas or geothermal energy."
However, these wastes may be regulated by the EPA or state agencies as
solid waste. Moreover, many ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes and waste compressor oils, are
regulated as hazardous wastes. Although the costs of managing hazardous
waste may be significant, the Partnership does not expect to experience
more burdensome costs than similarly situated companies
State water discharge regulations and federal waste discharge permitting
requirements adopted pursuant to the Federal Water Pollution Control Act
prohibit or are expected in the future to prohibit the discharge of
produced water and sand and some other substances related to the oil and
gas industry, into coastal waters. Although the costs to comply with such
mandates under state or federal law may be significant, the entire industry
will experience similar costs, and the Partnership does not believe that
these costs will have a material adverse impact on its financial condition
and operations.
The Partnership maintains insurance against "sudden and accidental"
occurrences, which may cover some, but not all, of the environmental risks
described above. Most significantly, the insurance we maintain will not
cover the risks described above which occur over a sustained period of
time. Further, there can be no assurance that such insurance will continue
to be available to cover all such costs or that such insurance will be
available at premium levels that justify its purchase. The occurrence of a
significant event not fully insured or indemnified against could have a
material adverse effect on our financial condition and operations.
Limited partners should be aware that the assessment of liability
associated with environmental liabilities is not always correlated to the
value of a particular project. Accordingly, liability associated with the
environment under local, state, or federal regulations, particularly clean
ups under CERCLA, can exceed the value of the Partnership's investment in
the associated site.
Partnership Employees
The Partnership has no employees; however the Managing General Partner and
CWEI have a staff of geologists, engineers, accountants, landmen and
clerical staff who engage in Partnership activities and operations and
perform additional services for the Partnership as needed. In addition,
the Partnership engages independent consultants such as petroleum engineers
and geologists as needed.
Item 2. Properties
As of December 31, 2004, the Partnership possessed an interest in oil and
gas properties located in Eddy and Lea Counties of New Mexico Andrews,
Crane, Ector, Garza, Howard, Pecos, Stonewall, Ward and Winkler Counties of
Texas. These properties consist of various interests in approximately 93
wells and units.
Reserves
The following table sets forth certain information as of December 31, 2004
with respect to the Partnership's estimated proved oil and gas reserves
pursuant to SEC guidelines, present value of proved reserves and
standardized measure of discounted future net cash flows.
Proved Developed Proved Total
------------------- ------- -------
------------------- ------- ----
--------- ----
Produci Nonprod Undevel Proved
ng ucing oped
------- ------- ------- -------
------- ------- ------- ----
----- ---- ----
Oil (Bbls) 225,000 - 13,000 238,000
Gas (Mcf) 990,000 - 52,000 1,042,0
00
Total (BOE) 390,000 - 22,000 412,000
Present value of $3,662, $ - $377,000 $4,039,
proved reserves 000 000
Standardized measure
of discounted
future net cash $3,942,
flows 000
The following table sets forth certain information as of December 31, 2004
regarding the Partnership's proved oil and gas reserves for certain
significant properties.
Proved Reserves Percen
t
----------------------- Present of
----------------------- Presen
---------- t
Total Percen Value of Value
Oil t of of
Oil Gas Equiva Total Proved Proved
lent Oil
(Bbls (Mcf) (BOE) Equiva Reserves Reserv
) lent es
----- ----- ------ ------ ------------ ------
----- ----- ------ ------ ---------- ------
--- - --- --- ---
Phillips- 201,0 969,0 363,00 88.1% 3,508,00 86.9%
Odessa 00 00 0 0
Other 37,00 73,00 49,000 11.9% 531,000 13.1%
0 0
----- ----- ------ ------ -------- ------
----- ----- ------ ------ ------ ------
- -- - ---
Total 238,0 1,042 412,00 100.0% $4,039, 100.0%
00 ,000 0 000
===== ===== ====== ====== ======== ======
= == = == ===
The estimates of proved reserves at December 31, 2004 and the present value
of proved reserves were derived from a report prepared by Ryder Scott
Company, L.P., petroleum consultants. These calculations were prepared
using standard geological and engineering methods generally accepted by the
petroleum industry and in accordance with SEC financial accounting and
reporting standards. The estimated present value of proved reserves does
not give effect to indirect expenses such as general and administrative
expenses, debt service (if any) and depletion, depreciation and
amortization.
In accordance with applicable financial accounting and reporting standards
of the SEC, the estimates of the Partnership's proved reserves and the
present value of proved reserves set forth herein are made using oil and
gas sales prices estimated to be in effect as of the date of such reserve
estimates and are held constant throughout the life of the properties.
Estimated quantities of proved reserves and their present value are
affected by changes in oil and gas prices. The average prices utilized for
the purposes of estimating the Partnership's proved reserves and the
present value of proved reserves as of December 31, 2004 were $41.85 per
Bbl of oil and natural gas liquids and $5.47 per Mcf of gas, as compared to
$31.42 per Bbl of oil and $5.51 per Mcf of gas as of December 31, 2003.
The reserve information shown is estimated. The accuracy of any reserve
estimate is a function of the quality of available geological, geophysical,
engineering and economic data, the precision of the engineering and
geological interpretation and judgment. The estimates of reserves, future
cash flows and present value are based on various assumptions, including
those prescribed by the SEC, and are inherently imprecise. Although the
Partnership believes these estimates are reasonable, actual future
production, cash flows, taxes, development expenditures, operating expenses
and quantities of recoverable oil and natural gas reserves may vary
substantially from these estimates. Also, the use of a 10% discount factor
for reporting purposes may not necessarily represent the most appropriate
discount factor, given actual interest rates and risks to which our
business or the oil and natural gas industry in general are subject.
Unanticipated depletion, if it occurs, will result in lower reserves than
previously estimated; thus an ultimately lower return for the Partnership.
Basic changes in past reserve estimates occur annually. As new data is
gathered during the subsequent year, the engineer must revise his earlier
estimates. A year of new information, which is pertinent to the estimation
of future recoverable volumes, is available during the subsequent year
evaluation. In applying industry standards and procedures, the new data
may cause the previous estimates to be revised. This revision may increase
or decrease the earlier estimated volumes. Pertinent information gathered
during the year may include actual production and decline rates, production
from offset wells drilled to the same geologic formation, increased or
decreased water production, workovers, and changes in lifting costs, among
others. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is
a party.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth
quarter of 2004 through the solicitation of proxies or otherwise.
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
Market Information
Limited partnership interests, or units, in the Partnership were initially
offered and sold for a price of $500. Limited partner units are not traded
on any exchange and there is no public or organized trading market for
them.
Number of Limited Partner Interest Holders
As of December 31, 2004, there were 565 holders of limited partner units in
the Partnership.
Distributions
Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and
Agreement of Limited Partnership "Net Cash Flow" is distributed to the
partners on a quarterly basis. "Net Cash Flow" is defined as "the cash
generated by the Partnership's investments in producing oil and gas
properties, less (i) General and Administrative Costs, (ii) Operating
Costs, and (iii) any reserves necessary to meet current and anticipated
needs of the Partnership, as determined in the sole discretion of the
Managing General Partner." During 2004, distributions were made totaling
$468,980, with $422,059 ($40.38 per unit) distributed to the limited
partners and $46,921 to the general partners.
Issuer Purchases of Equity Securities
The Managing General Partner has the right, but not the obligation in
accordance with the obligations set forth in the partnership agreement, to
purchase limited partnership units should an investor desire to sell. The
value of the unit is determined by adding the sum of (1) current assets
less liabilities and (2) the present value of the future net revenues
attributable to proved reserves and by discounting the future net revenues
at a rate not in excess of the prime rate charged by Bank One, a division
of JP Morgan Chase Bank, N.A. plus one percent (1%), which value shall be
further reduced by a risk factor discount of no more than one-third (1/3)
to be determined by the Managing General Partner in its sole and absolute
discretion under the partnership agreement. In 2004, no limited partner
units were purchased by the Managing General Partner.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31,
2004, 2003, 2002, 2001 and 2000 should be read in conjunction with the
financial statements included in Item 8:
Years ended December 31,
------------------------------------------------
---------
2004 2003 2002 2001 2000
------ ------ ------ ------ ------
Revenues $ 1,026,69 947,397 832,356 1,014,35 1,217,37
3 6 3
Net income before
cumulative effect
of
accounting changes 437,846 390,532 263,294 401,609 658,754
Net income 437,846 382,748 193,294 401,609 658,754
Partners' share
of net income:
General partners 45,318 40,375 28,629 45,461 67,876
Limited partners 392,528 342,373 164,665 356,148 590,878
Limited partners'
net income per
unit before
cumulative effect
of accounting 37.55
changes 33.42 22.45 34.07 56.53
Limited partners'
net income per unit 32.75
37.55 15.75 34.07 56.53
Limited partners'
cash distributions
per unit 40.38
38.16 18.81 55.63 54.00
Total assets $ 527,624 544,386 402,165 427,412 671,235
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
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 any net proceeds from operations to the
general and limited partners. Net revenues from producing oil and gas
properties are not reinvested in other revenue producing assets except to
the extent that producing facilities and wells are 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 farm-out arrangements and on 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 limited
partners has fluctuated over the past couple of years and is expected to
decline in later years based on these factors.
Critical Accounting Policies
The Partnership follows the full cost method of accounting for its oil and
gas properties. The full cost method subjects companies to quarterly
calculations of a "ceiling", or limitation on the amount of properties that
can be capitalized on the balance sheet. If the Partnership's capitalized
costs are in excess of the calculated ceiling, the excess must be written
off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of depletion, depreciation, and amortization
("DD&A").
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
Results of Operations
General Comparison of the Years Ended December 31, 2004 and 2003
The following table provides certain information regarding performance
factors for the years ended December 31, 2004 and 2003:
Year Ended Percenta
ge
December 31, Increase
2004 2003 (Decreas
e)
------ ------ --------
-------
Oil production in 17,461 19,500 (10%)
barrels
Gas production in mcf 65,438 79,900 (18%)
Total (BOE) 28,367 32,817 (14%)
Average price per $ 38.87 30%
barrel of oil 29.85
Average price per mcf $ 5.28 25%
of gas 4.23
Oil and gas revenue $ 1,024,33 920,073 11%
4
Production expense $ 467,794 433,045 8%
Partnership $ 468,980 442,773 6%
distributions
Limited partner $ 422,059 398,892 6%
distributions
Per unit distribution $ 40.38 6%
to limited partners 38.16
Number of limited 10,453 10,453
partner units
Revenues
The Partnership's oil and gas revenues increased to $1,024,334 from
$920,073 for the years ended December 31, 2004 and 2003, respectively, an
increase of 11%. The principal factors affecting the comparison of the
years ended December 31, 2004 and 2003 are as follows:
The average price for a barrel of oil received by the Partnership increased
during the year ended December 31, 2004 as compared to the year ended
December 31, 2003 by 30%, or $9.02 per barrel, resulting in an increase of
approximately $157,500 in revenues. Oil sales represented 66% of total oil
and gas sales during the year ended December 31, 2004 as compared to 63%
during the year ended December 31, 2003.
The average price for an mcf of gas received by the Partnership increased
during the same period by 25%, or $1.05 per mcf, resulting in an increase
of approximately $68,700 in revenues.
The total increase in revenues due to the change in prices received from
oil and gas production is approximately $226,200. 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.
Oil production decreased approximately 2,039 barrels or 10% during the year
ended December 31, 2004 as compared to the year ended December 31, 2003,
resulting in a decrease of approximately $60,900 in revenues.
Gas production decreased approximately 14,462 mcf or 18% during the same
period, resulting in a decrease of approximately $61,200 in revenues.
The total decrease in revenues due to the change in production is
approximately $122,100. The decrease in oil volumes is from down time on a
well for mechanical subsurface problems. The decrease in gas volumes is
from a gas well with fluids restricting production.
Costs and Expenses
Total costs and expenses increased to $588,847 from $556,865 for the years
ended December 31, 2004 and 2003, respectively, an increase of 6%. The
increase is the result of higher lease operating costs and general and
administrative costs, partially offset by a decrease in accretion expense
and depletion expense.
Lease operating costs and production taxes were 8% higher, or approximately
$34,700 more during the year ended December 31, 2004 as compared to the
year ended December 31, 2003.
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 5% or
approximately $4,000 during the year ended December 31, 2004 as compared to
the year ended December 31, 2003.
Depletion expense decreased to $15,339 for the year ended December 31, 2004
from $21,000 for the same period in 2003. This represents a decrease of
27%. The contributing factor to the decrease in depletion expense is in
relation to the BOE depletion rate for the year ended December 30, 2004,
which was $.54 applied to 28,367 BOE as compared to $.64 applied to 32,817
BOE for the same period in 2003. The lower depletion in 2004 is due to the
upward revision in reserve estimates resulting from higher oil and gas
prices.
Accretion expense decreased to $13,878 for the year ended December 31, 2004
from $14,971 for the same period in 2003. This represents a decrease of
7%.
Results of Operations
General Comparison of the Years Ended December 31, 2003 and 2002
The following table provides certain information regarding performance
factors for the years ended December 31, 2003 and 2002:
Year Ended Percenta
ge
December 31, Increase
2003 2002 (Decreas
e)
------ ------ --------
-------
Oil production in 19,500 22,100 (12%)
barrels
Gas production in mcf 79,900 110,800 (28%)
Total (BOE) 32,817 40,567 (19%)
Average price per $ 29.85 23%
barrel of oil 24.30
Average price per mcf $ 4.23 64%
of gas 2.58
Oil and gas revenue $ 920,073 822,546 12%
Production expense $ 433,045 466,318 (7%)
Partnership $ 442,773 218,523 103%
distributions
Limited partner $ 398,892 196,671 103%
distributions
Per unit distribution $ 38.16 103%
to limited partners 18.81
Number of limited 10,453 10,453
partner units
Revenues
The Partnership's oil and gas revenues increased to $920,073 from $822,546
for the years ended December 31, 2003 and 2002, respectively, an increase
of 12%. The principal factors affecting the comparison of the years ended
December 31, 2003 and 2002 are as follows:
The average price for a barrel of oil received by the Partnership increased
during the year ended December 31, 2003 as compared to the year ended
December 31, 2002 by 23%, or $5.55 per barrel, resulting in an increase of
approximately $108,200 in revenues. Oil sales represented 63% of total oil
and gas sales during the year ended December 31, 2003 as compared to 65%
during the year ended December 31, 2002.
The average price for an mcf of gas received by the Partnership increased
during the same period by 64%, or $1.65 per mcf, resulting in an increase
of approximately $131,800 in revenues.
The total increase in revenues due to the change in prices received from
oil and gas production is approximately $240,000. 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.
Oil production decreased approximately 2,600 barrels or 12% during the year
ended December 31, 2003 as compared to the year ended December 31, 2002,
resulting in a decrease of approximately $63,200 in revenues.
Gas production decreased approximately 30,900 mcf or 28% during the same
period, resulting in a decrease of approximately $79,700 in revenues.
The total decrease in revenues due to the change in production is
approximately $142,900. Oil and gas volumes declined due to the sale of
four leases. Also contributing to the decline in oil sales were steep
declines on two properties. The gas volume decline also included steep
decline on two wells and mechanical problems with surface equipment on a
lease.
Costs and Expenses
Total costs and expenses decreased to $556,865 from $569,062 for the years
ended December 31, 2003 and 2002, respectively, a decrease of 2%. The
decrease is the result of lower lease operating costs and depletion
expense, partially offset by the addition of accretion expense and an
increase in general and administrative costs.
Lease operating costs and production taxes were 7% lower, or approximately
$33,300 less during the year ended December 31, 2003 as compared to the
year ended December 31, 2002.
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 10% or
approximately $8,100 during the year ended December 31, 2003 as compared to
the year ended December 31, 2002.
Depletion expense decreased to $21,000 for the year ended December 31, 2003
from $23,000 for the same period in 2002. This represents a decrease of
9%. The contributing factor to the decrease in depletion expense is in
relation to the BOE depletion rate for the year ended December 30, 2003,
which was $.64 applied to 32,817 BOE as compared to $.57 applied to 40,567
BOE for the same period in 2002.
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 $179,335, a long term liability of
approximately $187,119 and a loss of approximately $7,784 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 December 31, 2003, the asset
retirement obligation was $202,113. The increase in the balance from
January 1, 2003 is due to accretion expense of $14,971 plus addition of new
well for $576, offset by the sale of a property for $553. The pro forma
amount of the asset retirement obligation as of December 31, 2002 was
approximately $187,119. The pro forma amounts of the asset retirement
obligation were measured using information, assumptions and interest rates
as of the adoption date of January 1, 2003.
Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2004, 2003 and 2002
was $437,846, $382,748 and $193,294, respectively. Partnership
distributions for the years ended December 31, 2004, 2003 and 2002 were
$468,980, $442,773 and $218,523, respectively. These changes are
indicative of the changes in oil and gas prices, production and properties
during 2004, 2003 and 2002.
The sources for the 2004 distributions of $468,980 were oil and gas
operations of approximately $434,500 and the change in oil and gas
properties of approximately $(13,000), with the balance from available cash
on hand at the beginning of the period. The sources for the 2003
distributions of $442,773 were oil and gas operations of approximately
$474,000 and the change in oil and gas properties of approximately $8,400,
resulting in excess cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2004 were $468,980
of which $422,059 ($40.38 per unit) was distributed to the limited partners
and $46,921 to the general partners. Total distributions during the year
ended December 31, 2003 were $442,773 of which $398,892 ($38.16 per unit)
was distributed to the limited partners and $43,881 to the general
partners. Total distributions during the year ended December 31, 2002 were
$218,523 of which $196,671 ($18.81 per unit) was distributed to the limited
partners and $21,852 to the general partners.
Cumulative cash distributions of $8,571,203 have been made to the general
and limited partners as of December 31, 2004. As of December 31, 2004,
$7,783,322 or $744.60 per limited partner unit has been distributed to the
limited partners, representing 149% of contributed capital.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $434,500 in
2004 compared to $474,000 in 2003 and approximately $244,200 in 2002.
Cash flows provided by (used in) investing activities were approximately
$(13,000) in 2004 compared to $8,400 in 2003 and approximately $(5,600) in
2002. The principal use of the 2004 cash flow from investing activities
was the addition of oil and gas properties.
Cash flows used in financing activities were approximately $468,300 in 2004
compared to $442,600 in 2003 and approximately $218,500 in 2002. The only
use in financing activities was the distributions to partners.
As of December 31, 2004, the Partnership had approximately $138,000 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.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 153 "Exchanges of
Nonmonetary Assets, an amendment of APB Opinion No. 29" ("SFAS 153").
SFAS 153 specifies the criteria required to record a nonmonetary asset
exchange using carryover basis. SFAS 153 is effective for nonmonetary
asset exchanges occurring after July 1, 2005. The Partnership will adopt
this statement in the third quarter of 2005, and it is not expected to have
a material effect on the financial statements when adopted.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC staff's
views regarding SFAS No. 143 and its impact on both the full-cost ceiling
test and the calculation of depletion expense. In accordance with SAB 106,
beginning in the first quarter of 2005, undiscounted abandonment costs for
wells to be drilled in the future to develop proved reserves should be
included in the unamortized cost of oil and gas properties, net of related
salvage value, for purposes of computing depreciation, depletion and
amortization ("DD&A"). The effect of including undiscounted abandonment
costs of future wells to the undiscounted cost of oil and gas properties
may increase DD&A expense in future periods, however, the Partnership
currently does not believe SAB 106 will have a material impact on our
financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Page
Report of Independent Registered Public Accounting Firm 20
Balance Sheets 21
Statements of Operations 22
Statement of Changes in Partners' Equity 23
Statements of Cash Flows 24
Notes to Financial Statements 26
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
The Partners
Southwest Oil & Gas Income Fund IX-A, L.P.
(A Delaware Limited Partnership)
We have audited the accompanying balance sheets of Southwest Oil & Gas
Income Fund IX-A, L.P. (the "Partnership") as of December 31, 2004 and
2003, and the related statements of operations, partners' equity, and cash
flows for each of the years in the three-year period ended December 31,
2004. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Oil & Gas
Income Fund IX-A, L.P. as of December 31, 2004 and 2003, and the results of
its operations and its cash flows for each of the years in the three-year
period ended December 31, 2004, in conformity with U.S. generally accepted
accounting principles.
As discussed in Note 4 to the financial statements, the Partnership changed
its method of computing depletion in 2002. Also, as discussed in Note 3 to
the financial statements, the Partnership changed its method of accounting
for asset retirement obligations as of January 1, 2003.
KPMG LLP
Dallas, Texas
March 26, 2005
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Balance Sheets
December 31, 2004 and 2003
2004 2003
------ ------
Assets
- ----------
Current assets:
Cash and cash equivalents $ 62,336 109,200
Receivable from Managing 77,125 44,518
General Partner
-------- --------
----- -----
Total current assets 139,461 153,718
-------- --------
----- -----
Oil and gas properties -
using the full-
cost method of accounting 3,197,99 3,185,16
5 0
Less accumulated
depreciation,
depletion and 2,809,83 2,794,49
amortization 2 2
-------- --------
----- -----
Net oil and gas 388,163 390,668
properties
-------- --------
----- -----
$ 527,624 544,386
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- ------------
Current liability - $ 1,509 851
distributions payable
-------- --------
----- -----
Asset retirement obligation 215,827 202,113
-------- --------
----- -----
Partners' equity (deficit):
General partners (63,413) (61,810)
Limited partners 373,701 403,232
-------- --------
----- -----
Total partners' equity 310,288 341,422
-------- --------
----- -----
$ 527,624 544,386
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Statements of Operations
Years ended December 31, 2004, 2003 and 2002
2004 2003 2002
------ ------ ------
Revenues
- -------------
Oil and gas $ 1,024,33 920,073 822,546
4
Interest from operations 654 971 647
Other 1,705 26,353 9,163
-------- -------- --------
---- ---- ----
1,026,69 947,397 832,356
3
-------- -------- --------
---- ---- ----
Expenses
- ------------
Production 467,794 433,045 466,318
Depreciation, depletion and 15,339 21,000 23,000
amortization
Accretion expense 13,878 14,971 -
General and administrative 91,836 87,849 79,744
-------- -------- --------
---- ---- ----
588,847 556,865 569,062
-------- -------- --------
---- ---- ----
Net income before cumulative
effects
of accounting changes 437,846 390,532 263,294
Cumulative effect of change in
accounting
principle - SFAS No. 143 - - (7,784) -
See Note 3
Cumulative effect of change in
accounting principle
- change in depletion method - - (70,000)
- - See Note 4
-------- -------- --------
---- ---- ----
Net income $ 437,846 382,748 193,294
======= ======= =======
Net income allocated to:
Managing General Partner $ 40,786 36,337 25,766
======= ======= =======
General Partner $ 4,532 4,038 2,863
======= ======= =======
Limited partners $ 392,528 342,373 164,665
======= ======= =======
Per limited partner unit $ 37.55
before cumulative effect 33.42 22.45
Cumulative effects per - (.67)
limited partner unit (6.70)
-------- -------- --------
---- ---- ----
Per limited partner unit $ 37.55
32.75 15.75
======= ======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Statement of Changes in Partners' Equity
Years ended December 31, 2004, 2003 and 2002
General Limited
Partners Partners Total
-------- -------- -----
Balance at December 31, 2001 $ (65,081) 491,757 426,676
Net income 28,629 164,665 193,294
Distributions (21,852) (196,671 (218,523
) )
-------- -------- --------
-- -- --
Balance at December 31, 2002 (58,304) 459,751 401,447
Net income 40,375 342,373 382,748
Distributions (43,881) (398,892 (442,773
) )
-------- -------- --------
-- -- --
Balance at December 31, 2003 (61,810) 403,232 341,422
Net income 45,318 392,528 437,846
Distributions (46,921) (422,059 (468,980
) )
-------- -------- --------
-- -- --
Balance at December 31, 2004 $ (63,413) 373,701 310,288
====== ====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2004, 2003 and 2002
2004 2003 2002
------ ------ ------
Cash flows from operating
activities:
Cash received from oil and $ 1,024,10 915,049 800,557
gas sales 2
Cash paid for production
expense, administrative
fees and general and (592,004 (468,408 (566,121
administrative overhead ) ) )
Interest received 654 971 647
Other 1,705 26,353 9,163
-------- -------- --------
----- ----- -----
Net cash provided by 434,457 473,965 244,246
operating activities
-------- -------- --------
----- ----- -----
Cash flows from investing
activities:
Additions to oil and gas (12,999) (4,132) (535)
properties
Sale of oil and gas - 12,501 6,183
properties
-------- -------- --------
----- ----- -----
Net cash (used in) provided (12,999) 8,369 5,648
by investing activities
-------- -------- --------
----- ----- -----
Cash flows used in financing
activities:
Distributions to partners (468,322 (442,640 (218,541
) ) )
-------- -------- --------
----- ----- -----
Net (decrease) increase in (46,864) 39,694 31,353
cash and cash equivalents
Beginning of year 109,200 69,506 38,153
-------- -------- --------
----- ----- -----
End of year $ 62,336 109,200 69,506
======= ======= =======
(continu
ed)
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Statements of Cash Flows
Years ended December 31, 2004, 2003 and 2002 (continued)
2004 2003 2002
------ ------ ------
Reconciliation of net income
to net cash
provided by operating
activities:
Net income $ 437,846 382,748 193,294
Adjustments to reconcile net
income to net
cash provided by operating
activities:
Depreciation, depletion and 15,339 21,000 23,000
amortization
Accretion expense 13,878 14,971 -
Cumulative effects of change - 7,784 70,000
in accounting principle
Increase in receivables (232) (5,024) (21,989)
(Decrease) increase in (32,374) 52,486 (20,059)
payables
-------- -------- --------
----- ----- -----
Net cash provided by operating $ 434,457 473,965 244,246
activities
======= ======= =======
Noncash investing and
financing activities:
Increase in oil and gas
properties - Adoption
of SFAS No. 143 $ - 179,335 -
======= ======= =======
Increase in oil and gas
properties - SFAS No. 143
Additional well due to farm- $ - 576 -
out arrangement
======= ======= =======
Decrease in oil and gas
properties - SFAS No. 143
Sale of property $ - (553) -
======= ======= =======
Decrease in oil and gas
properties - SFAS No. 143
Plug and abandoned wells $ 164 - -
======= ======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Oil & Gas Income Fund IX-A, L.P. was organized under the
laws of the state of Delaware on March 9, 1989, for the purpose of
acquiring producing oil and gas properties and to produce and market
crude oil and natural gas produced from such properties for a term of
50 years unless terminated at an earlier date as provided for in the
Partnership Agreement. The Partnership sells its oil and gas
production to a variety of purchasers with the prices it receives
being dependent upon the oil and gas economy. Southwest Royalties,
Inc., a wholly owned subsidiary of Clayton Williams Energy, Inc.,
serves as the Managing General Partner. Revenues, costs and expenses
are allocated as follows:
Limited General
Partners Partners
-------- --------
Interest income on capital 100% -
contributions
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and offering 100% -
costs (1)
Amortization of organization 100% -
costs
Property acquisition costs 100% -
Gain/loss on property 90% 10%
disposition
Operating and administrative 90% 10%
costs (2)
Depreciation, depletion and
amortization
of oil and gas properties 100% -
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
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and
development of oil and gas reserves are capitalized. Gain or loss on
the sale of oil and gas properties is not recognized unless
significant oil and gas reserves are involved.
Should the net capitalized costs exceed the estimated present value of
oil and gas reserves, discounted at 10%, such excess costs would be
charged to current expense. As of December 31, 2004, 2003 and 2002
the net capitalized costs did not exceed the estimated present value
of oil and gas reserves.
Estimates and Uncertainties
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. The Partnership's depletion
calculation and full-cost ceiling test for oil and gas properties uses
oil and gas reserves estimates, which are inherently imprecise. Actual
results could differ from those estimates.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Syndication Costs
Syndication costs are accounted for as a reduction of partnership
equity.
Environmental Costs
The Partnership is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and
may require the Partnership to remove or mitigate the environmental
effects of the disposal or release of petroleum or chemical substances
at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Costs, which
improve a property as compared with the condition of the property when
originally constructed or acquired and costs, which prevent future
environmental contamination are capitalized. Expenditures that relate
to an existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for expenditures
of a non-capital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably
estimated.
Revenue Recognition
We recognize oil and gas sales when delivery to the purchaser has
occurred and title has transferred. This occurs when production has
been delivered to a pipeline or transport vehicle.
Gas Balancing
The Partnership utilizes the sales method of accounting for gas-
balancing arrangements. Under this method the Partnership recognizes
sales revenue on all gas sold. As of December 31, 2004 and 2003 the
Partnership was overproduced by 403 mcf of gas.
Income Taxes
No provision for income taxes is reflected in these financial
statements, since the tax effects of the Partnership's income or loss
are passed through to the individual partners.
In accordance with the requirements of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" the
Partnership's tax basis in its net oil and gas properties at December
31, 2004 and 2003 is $188,942 and $181,816 less than, respectively,
than that shown on the accompanying Balance Sheet in accordance with
generally accepted accounting principles.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Partnership considers
all highly liquid debt instruments purchased with a maturity of three
months or less to be cash equivalents. The Partnership maintains its
cash at one financial institution.
Number of Limited Partner Units
As of December 31, 2004, 2003 and 2002 and there were 10,453 limited
partner units outstanding held by 565, 566 and 562 partners.
Concentrations of Credit Risk
The Partnership is subject to credit risk through trade receivables.
Although a substantial portion of its debtors' ability to pay is
dependent upon the oil and gas industry, credit risk is minimized due
to a large customer base. All partnership revenues are received by
the Managing General Partner and subsequently remitted to the
partnership and all expenses are paid by the Managing General Partner
and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair
value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit
The net income (loss) per limited partnership unit is calculated by
using the number of outstanding limited partnership units.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards No. 153 "Exchanges
of Nonmonetary Assets, an amendment of APB Opinion No. 29"
("SFAS 153"). SFAS 153 specifies the criteria required to record a
nonmonetary asset exchange using carryover basis. SFAS 153 is
effective for nonmonetary asset exchanges occurring after July 1,
2005. The Partnership will adopt this statement in the third quarter
of 2005, and it is not expected to have a material effect on the
financial statements when adopted.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC
staff's views regarding SFAS No. 143 and its impact on both the full-
cost ceiling test and the calculation of depletion expense. In
accordance with SAB 106, beginning in the first quarter of 2005,
undiscounted abandonment costs for wells to be drilled in the future
to develop proved reserves should be included in the unamortized cost
of oil and gas properties, net of related salvage value, for purposes
of computing depreciation, depletion and amortization ("DD&A"). The
effect of including undiscounted abandonment costs of future wells to
the undiscounted cost of oil and gas properties may increase DD&A
expense in future periods, however, the Partnership currently does not
believe SAB 106 will have a material impact on our financial
statements.
Depletion Policy
In 2002, the Partnership changed methods of accounting for depletion
of capitalized costs from the units-of-revenue method to the units-of-
production method. (See Note 4)
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 $179,335, a long term liability of
approximately $187,119 and a loss of approximately $7,784 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 December
31, 2004, the asset retirement obligation was $215,827. The increase
in the balance from January 1, 2004 is due to accretion expense of
$13,878 less $164 for wells plugged and abandoned. The pro forma
amount of the asset retirement obligation as of December 31, 2002 was
approximately $187,119. The pro forma amounts of the asset retirement
obligation were measured using information, assumptions and interest
rates as of the adoption date of January 1, 2003. The pro forma
amounts for the year ended December 31, 2002, which is presented
below, reflect the effect of retroactive application of SFAS No. 143.
2002
------
Pro forma amounts assuming
change is applied
retroactively:
Net income before cumulative
effect
for change in depletion $ 249,522
method
=======
Per limited partner unit $ 21.26
(10,453.0 units)
=======
Net income $ 179,522
=======
Per limited partner unit $ 14.57
(10,453.0 units)
=======
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
4. Cumulative effect of a change in accounting principle - change in
depletion method
In 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 $70,000 effective as of January
1, 2002. The Partnership's depletion for the years subsequent to 2001
has been calculated using the units-of-production method.
5. Commitments and Contingent Liabilities
The Managing General Partner has the right, but not the obligation, to
purchase limited partnership units should an investor desire to sell.
The value of the unit is determined by adding the sum of (1) current
assets less liabilities and (2) the present value of the future net
revenues attributable to proved reserves and by discounting the future
net revenues at a rate not in excess of the prime rate charged by Bank
One, a division of JP Morgan Chase Bank, N.A. plus one percent (1%),
which value shall be further reduced by a risk factor discount of no
more than one-third (1/3) to be determined by the Managing General
Partner in its sole and absolute discretion.
The Partnership is subject to various federal, state and local
environmental laws and regulations, which establish standards and
requirements for protection of the environment. The Partnership
cannot predict the future impact of such standards and requirements,
which are subject to change and can have retroactive effectiveness.
The Partnership continues to monitor the status of these laws and
regulations.
As of December 31, 2004, the Partnership has not been fined, cited or
notified of any environmental violations and management was not aware
of any unasserted violations, which would have a material adverse
effect upon capital expenditures, earnings or the competitive position
in the oil and gas industry. However, the Managing General Partner
does recognize by the very nature of its business, material costs
could be incurred in the near term to bring the Partnership into total
compliance. The amount of such future expenditures is not
determinable due to several factors, including the unknown magnitude
of possible contaminations, the unknown timing and extent of the
corrective actions which may be required, the determination of the
Partnership's liability in proportion to other responsible parties and
the extent to which such expenditures are recoverable from insurance
or indemnifications from prior owners of Partnership's properties.
6. Related Party Transactions
A significant portion of the oil and gas properties in which the
Partnership has an interest are operated by and purchased from the
Managing General Partner. As provided for in the operating agreement
for each respective oil and gas property in which the Partnership has
an interest, the operator is paid an amount for administrative
overhead attributable to operating such properties, with such amounts
to Southwest Royalties, Inc. as operator approximating $60,800,
$66,300 and $79,200 for the years ended December 31, 2004, 2003 and
2002, respectively. In addition, the Managing General Partner and
certain officers and employees may have an interest in some of the
properties that the Partnership also participates.
Southwest Royalties, Inc., the Managing General Partner, was paid
$73,200 during 2004, 2003 and 2002 as an administrative fee for
indirect general and administrative overhead expenses. The
administrative fees are included in general and administrative expense
on the statement of operations.
Receivables from Southwest Royalties, Inc., the Managing General
Partner, of approximately $77,100 and $44,500 are from oil and gas
production, net of lease operating costs and production taxes, as of
December 31, 2004 and 2003, respectively.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Oil and Gas Reserves Information (unaudited)
The estimates of proved oil and gas reserves utilized in the
preparation of the financial statements were prepared by independent
petroleum engineers. Such estimates are in accordance with guidelines
established by the Securities and Exchange Commission and the
Financial Accounting Standards Board, which require that reserve
reports be prepared under economic and operating conditions existing
at the registrant's year end with no provision for price and cost
escalations except by contractual arrangements. Future cash inflows
were computed by applying year-end prices to the year-end quantities
of proved reserves. Future development, abandonment and production
costs were computed by estimating the expenditures to be incurred in
developing, producing, and abandoning proved oil and gas reserves at
the end of the year, based on year-end costs. All of the
Partnership's reserves are located in the United States. For
information about the Partnership's results of operations from oil and
gas producing activities, see the accompanying statements of
operations.
The Partnership's interest in proved oil and gas reserves is as
follows:
Oil Gas
(bbls) (mcf)
-------- --------
----- ----
Total Proved -
January 1, 2002 209,000 839,000
Revisions of previous 28,000 190,000
estimates
Production (22,000) (111,000
)
-------- --------
---- ----
December 31, 2002 215,000 918,000
Sales of reserves in place (2,000) (3,000)
Revisions of previous 58,000 211,000
estimates
Production (20,000) (80,000)
-------- --------
---- ----
December 31, 2003 251,000 1,046,00
0
Revisions of previous 4,000 61,000
estimates
Production (17,000) (65,000)
-------- --------
---- ----
December 31, 2004 238,000 1,042,00
0
======= =======
Proved developed reserves -
December 31, 2002 202,000 797,000
======= =======
December 31, 2003 238,000 994,000
======= =======
December 31, 2004 225,000 990,000
======= =======
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Oil and Gas Reserves Information (unaudited) - continued
Oil price adjustments were made in the individual evaluations to
reflect oil quality, gathering and transportation costs. The results
of the reserve report as of December 31, 2004, 2003 and 2002 are an
average price of $41.85, $31.42 and $29.28 per barrel.
Gas price adjustments were made in the individual evaluations to
reflect BTU content, gathering and transportation costs and gas
processing and shrinkage. The results of the reserve report as of
December 31, 2004, 2003 and 2002 are an average price of $5.47, $5.51
and $4.30 per Mcf.
The evaluation of oil and gas properties is not an exact science and
inevitably involves a significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any given property is
capable of producing. Estimates of oil and gas reserves are based on
available geological and engineering data, the extent and quality of
which may vary in each case and, in certain instances, may prove to be
inaccurate. Consequently, properties may be depleted more rapidly
than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves
than previously estimated; thus an ultimately lower return for the
Partnership. Basic changes in past reserve estimates occur annually.
As new data is gathered during the subsequent year, the engineer must
revise his earlier estimates. A year of new information, which is
pertinent to the estimation of future recoverable volumes, is
available during the subsequent year evaluation.
In applying industry standards and procedures, the new data may cause
the previous estimates to be revised. This revision may increase or
decrease the earlier estimated volumes. Pertinent information
gathered during the year may include actual production and decline
rates, production from offset wells drilled to the same geologic
formation, increased or decreased water production, workovers, and
changes in lifting costs, among others. Accordingly, reserve
estimates are often different from the quantities of oil and gas that
are ultimately recovered.
The Partnership has reserves, which are classified as proved developed
and proved undeveloped. All of the proved reserves are included in
the engineering reports, which evaluate the Partnership's present
reserves.
Because the Partnership does not engage in drilling activities, the
development of proved undeveloped reserves is conducted pursuant to
farm-out arrangements with the Managing General Partner or unrelated
third parties. Generally, the Partnership retains a carried interest
such as an overriding royalty interest under the terms of a farm-out.
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
7. Oil and Gas Reserves Information (unaudited) - continued
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 2004, 2003 and 2002 is
presented below:
2004 2003 2002
------ ------ ------
Future cash inflows $ 15,665,0 13,646,0 10,248,0
00 00 00
Production, development and
abandonment costs 6,747,00 5,915,00 4,482,00
0 0 0
-------- -------- --------
------ ------ -----
Future net cash flows 8,918,00 7,731,00 5,766,00
0 0 0
10% annual discount for
estimated
timing of cash flows 4,976,00 3,945,00 2,406,00
0 0 0
-------- -------- --------
----- ------ -----
Standardized measure of
discounted
future net cash flows $ 3,942,00 3,786,00 3,360,00
0 0 0
======= ======== =======
Changes in the standardized measure of discounted future net cash
flows relating to proved reserves for the years ended December 31,
2004, 2003 and 2002 are as follows:
2004 2003 2002
------ ------ ------
Sales of oil and gas
produced,
net of production costs $ (557,000 (487,000 (356,000
) ) )
Changes in prices and 636,000 404,000 1,375,00
production costs 0
Changes of production rates
(timing) and others (437,000 (628,000 (84,000)
) )
Sales of minerals in place - (28,000) -
Revisions of previous
quantities estimates 135,000 829,000 545,000
Accretion of discount 379,000 336,000 171,000
Discounted future net
cash flows -
Beginning of year 3,786,00 3,360,00 1,709,00
0 0 0
-------- -------- --------
---- ---- ----
End of year $ 3,942,00 3,786,00 3,360,00
0 0 0
======= ======= =======
Southwest Oil & Gas Income Fund IX-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
8. Selected Quarterly Financial Results - (unaudited)
Quarter
--------------------------------------
--------------------------------------
-
First Second Third Fourth
------ -------- ------- --------
--- -
2004:
Total revenues $ 237,077 234,204 267,911 287,501
Total expenses 151,090 122,003 155,085 160,669
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 85,987 112,201 112,826 126,832
======= ======= ======= =======
Net income per limited $ 7.37
partners unit 9.62 9.68 10.88
======= ======= ======= =======
Quarter
--------------------------------------
--------------------------------------
-
First Second Third Fourth
------ -------- ------- --------
--- -
2003:
Total revenues $ 280,508 218,525 223,733 224,631
Total expenses 124,302 153,519 131,352 147,692
-------- -------- -------- --------
---- ---- ---- ----
Net income before
cumulative effect of
a change in accounting 156,206 65,006 92,381 76,939
principle
Cumulative effect of SFAS (7,784) - - -
No. 143
-------- -------- -------- --------
---- ---- ---- ----
Net income $ 148,422 65,006 92,381 76,939
======= ======= ======= =======
Per limited partner unit
amounts:
Income before cumulative
effect of a
change in accounting $ 13.39
principle 5.54 7.91 6.58
Cumulative effect of SFAS (.67) - - -
No. 143
-------- -------- -------- --------
---- ---- ---- ----
Net income per limited $ 12.72
partners unit 5.54 7.91 6.58
======= ======= ======= =======
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None
Item 9A. 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 quarter ended December 31,
2004 that has materially affected, or is reasonably likely to materially
affect, its internal control over financial reporting.
Item 9B. Other Information
None.
Part III
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as
Managing General Partner. Since the Managing General Partner is a wholly
owned subsidiary of CWEI, the directors of the Managing General Partner are
elected by management of CWEI. Each director the Managing General Partner
serves for a term of one year. Following is certain information concerning
each of the directors and executive officers of the Managing General
Partner.
CLAYTON W. WILLIAMS, age 73, is Chairman of the Board and a director of the
Managing General Partner, having served in this capacity since May 2004.
Mr. Williams also serves as Chairman of the Board, President, Chief
Executive Officer and a director of CWEI.
L. PAUL LATHAM, age 53, is President, Chief Executive Officer and a
director of the Managing General Partner, having served in this capacity
since May 2004. Mr. Latham also serves as Executive Vice President, Chief
Operating Officer and a director of CWEI.
MEL G. RIGGS, age 50, is Vice President, Chief Financial Officer, Treasurer
and a director of the Managing General Partner, having served in this
capacity since May 2004. Mr. Riggs also serves as Senior Vice President
and Chief Financial Officer of CWEI.
JERRY F. GRONER, age 42, is Vice President - Land and Lease Administration
of the Managing General Partner, having served in this capacity since May
2004. Mr. Groner also serves as Vice President - Land and Lease
Administration of CWEI.
D. GREGORY BENTON, age 43, is Vice President - Engineering of the Managing
General Partner, having served in this capacity since May 2004. Mr. Benton
also serves as Exploitation Manager of CWEI.
ROBERT C. LYON, age 68, is Vice President - Gas Gathering and Marketing of
the Managing General Partner, having served in this capacity since May
2004. Mr. Lyon also serves as Vice President - Gas Gathering and Marketing
of CWEI.
T. MARK TISDALE, age 48, is Vice President and Secretary of the Managing
General Partner, having served in this capacity since May 2004. Mr.
Tisdale also serves as Vice President and General Counsel of CWEI.
There are no family relationships among the directors and officers of the
Managing General Partner except that Mr. Groner is the son-in-law of Mr.
Williams.
Code of Ethics
As a wholly owned subsidiary of CWEI, the Managing General Partner is
subject to a Code of Conduct and Ethics ("Code") that applies to all
directors, executive officers and employees of CWEI and the Managing
General Partner. This Code assists employees in complying with the law, in
resolving ethical issues that may arise, and in complying with policies
established by CWEI. This Code is also designed to promote, among other
things, ethical handling of actual or apparent conflicts of interest; full,
fair, accurate and timely disclosure in filings with the SEC; compliance
with law; and prompt internal reporting of violations of the Code. This
Code is available on the website of CWEI at www.claytonwilliams.com under
"Investor Relations/Documents".
Item 11. Executive Compensation
The Partnership does not employ any directors, executive officers or
employees. The Managing General Partner receives an administrative fee for
the management of the Partnership. The Managing General Partner received
$73,200 during 2004, 2003 and 2002 as an annual administrative fee. The
executive officers of the Managing General Partner do not receive any form
of compensation, from the Partnership; instead, their compensation is paid
solely by Southwest. The executive officers, however, may occasionally
perform administrative duties for the Partnership but receive no additional
compensation for this work.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no limited partners who own of record, or are known by the
Managing General Partner to beneficially own, more than five percent of the
Partnership's limited partnership interests, other than the Managing
General Partner.
Through repurchase offers to the limited partners, the Managing General
Partner owns 498.5 limited partner units, a 4.3% limited partner interest.
The Managing General Partner's total percentage interest ownership in the
Partnership is 14.3%.
No officer or director of the Managing General Partner directly owns units
in the Partnership. CWEI is considered to be a beneficial owner of the
limited partner units acquired by the Managing General Partner by virtue of
its ownership of the Managing General Partner. Beneficial ownership is
determined in accordance with the rules of the Securities and Exchange
Commission and includes voting or investment power with respect to the
limited partner units.
Item 13. Certain Relationships and Related Transactions
In 2004, the Managing General Partner received $73,200 as an administrative
fee. This amount is part of the general and administrative expenses
incurred by the Partnership.
In some instances the Managing General Partner and its affiliates may be
working interest owners in an oil and gas property in which the Partnership
also has a working interest. Certain properties in which the Partnership
has an interest are operated by the Managing General Partner, who was paid
approximately $60,800 for administrative overhead attributable to operating
such properties during 2004.
The terms of the above transactions are similar to ones, which would have
been obtained through arm's length negotiations with unaffiliated third
parties.
Item 14. Principal Accounting Fees and Services
The following table presents fees for professional audit services rendered
by KPMG LLP for the audit of the Partnership's annual financial statements
for the years ended December 31, 2004 and 2003 and fees billed for other
services rendered by KPMG during those periods.
For the Year Ended December 2004 2003
31,
------- ------
Audit Fees $12,865 $
8,434
Audit Related Fees -
-
Tax Fees -
-
All Other Fees -
-
------ ------
----- -----
TOTAL $12,865 $
8,434
======
======
The Audit Committee of the CWEI reviewed and approved, in advance, all
audit and non-audit services provided by KPMG LLP.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements:
Included in Part II of this report --
Report of Independent Registered Public Accounting Firm
Balance Sheets
Statements of Operations
Statement of Changes in Partners' Equity
Statements of Cash Flows
Notes to Financial Statements
(2) Schedules required by Article 12 of Regulation S-
X are either omitted because they are not applicable or
because the required information is shown in the
financial statements or the notes thereto.
(3) Exhibits:
4 (a) Certificate of Limited
Partnership of Southwest Oil & Gas Income Fund IX-
A, L.P., dated March 9, 1989. (Incorporated by
reference from Partnership's Form 10-K for the
fiscal year ended December 31, 1989.)
(b) Agreement of Limited
Partnership of Southwest Oil & Gas Income Fund IX-
A, L.P. dated October 25, 1989. (Incorporated by
reference from Partnership's Form 10-K for the
fiscal year ended December 31, 1987.)
(c) Certificate of Amendment of
Limited Partnership of Southwest Oil & Gas Income
Fund IX-A, L.P., dated July 21, 1987.
(Incorporated by reference from Partnership's
Form 10-K for the fiscal year ended December 31,
1987.)
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
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Partnership has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Oil & Gas Income Fund IX-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: March 31, 2005
In accordance with the Exchange Act, this report has been signed below by
the following persons on behalf of the Registrant and in the capacities and
on the dates indicated.
/s/ Clayton W Williams /s/ L. Paul Latham
Clayton W. Williams, L. Paul Latham,
Chairman of the Board President and a Director
and a Director
Date: March 31, 2005 Date: March 31, 2005
/s/ Mel G. Riggs
Mel G. Riggs, Vice
President - Finance,
Treasurer and a Director
Date: March 31, 2005
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil & Gas
Income Fund IX-A, L.P.
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: March 31, 2005 /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund IX-A,
L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil & Gas
Income Fund IX-A, L.P.,
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: March 31, 2005 /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund IX-A,
L.P.
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND
CHIEF FINANCIAL OFFICER
Pursuant to 18 U.S.C. 1350 and in connection with the accompanying report
on Form 10-K for the period ended December 31, 2004 that is being filed
concurrently with the Securities and Exchange Commission on the date hereof
(the "Report"), each of the undersigned officers of Southwest Oil & Gas
Income Fund IX-A, L.P. (the "Company"), hereby certifies 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.
/s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund IX-
A, L.P.
March 31, 2005
/s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Oil & Gas Income Fund IX-
A, L.P.
March 31, 2005