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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(MARK ONE)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 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 0-20298
SOUTHWEST ROYALTIES INSTITUTIONAL 1990-91 INCOME PROGRAM
Southwest Royalties Institutional Income Fund X-C, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2374449
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
Midland, Texas 79701
(Address of principal executive offices)
(432) 686-9927
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:
Yes X No ___
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 22.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry that are used in this filing. All volumes of
natural gas referred to herein are stated at the legal pressure base to the
state or area where the reserves exit and at 60 degrees Fahrenheit and in
most instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42 United States gallons liquid volume.
Developmental well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir or to extend a known
reservoir.
Farm-out arrangement. An agreement whereby the owner of the leasehold
or working interest agrees to assign his interest in certain specific
acreage to the assignee, retaining some interest, such as an overriding
royalty interest, subject to the drilling of one (1) or more wells or other
performance by the assignee.
Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature and/or stratigraphic condition.
Mcf. One thousand cubic feet.
Net Profits Interest. An agreement whereby the owner receives a
specified percentage of the defined net profits from a producing property
in exchange for consideration paid. The net profits interest owner will
not otherwise participate in additional costs and expenses of the property.
Oil. Crude oil, condensate and natural gas liquids.
Overriding royalty interest. Interests that are carved out of a
working interest, and their duration is limited by the term of the lease
under which they are created.
Present value and PV-10 Value. When used with respect to oil and
natural gas reserves, the estimated future net revenue to be generated from
the production of proved reserves, determined in all material respects in
accordance with the rules and regulations of the SEC (generally using
prices and costs in effect as of the date indicated) without giving effect
to non-property related expenses such as general and administrative
expenses, debt service and future income tax expenses or to depreciation,
depletion and amortization, discounted using an annual discount rate of
10%.
Production costs. Costs incurred to operate and maintain wells and
related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of
operating and maintaining those wells and related equipment and facilities.
Proved Area. The part of a property to which proved reserves have been
specifically attributed.
Proved developed oil and gas reserves. Proved developed oil and gas
reserves are reserves that can be expected to be recovered from existing
wells with existing equipment and operating methods.
Proved properties. Properties with proved reserves.
Proved reserves. The estimated quantities of crude oil, natural gas,
and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil or gas that is confined by
impermeable rock or water barriers and is individual and separate from
other reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of
costs of production.
Working interest. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property
and a share of production.
Workover. Operations on a producing well to restore or increase
production.
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the notes thereto for
the year ended December 31, 2003, which are found in the Registrant's Form
10-K Report for 2003 filed with the Securities and Exchange Commission.
The December 31, 2003 balance sheet included herein has been taken from the
Registrant's 2003 Form 10-K Report. Operating results for the three month
period ended March 31, 2004 are not necessarily indicative of the results
that may be expected for the full year.
Southwest Royalties Institutional Income Fund X-C, L.P.
Balance Sheets
March December
31, 31,
2004 2003
---- ----
(unaudit
ed)
Assets
- ----------
Current assets:
Cash and cash equivalents $ 24,254 26,631
Receivable from Managing 87,252 40,531
General Partner
-------- --------
---- ----
Total current assets 111,506 67,162
-------- --------
---- ----
Oil and gas properties -
using the full-
method of accounting 2,395,60 2,395,60
1 1
Less accumulated
depreciation,
depletion and 2,231,14 2,228,14
amortization 3 3
-------- --------
---- ----
Net oil and gas 164,458 167,458
properties
-------- --------
---- ----
$ 275,964 234,620
======= =======
Liabilities and Partners'
Equity
- ----------------------------
- -----------
Asset retirement obligation $ 755,662 740,845
-------- --------
---- ----
Partners' equity:
General partners (89,502) (92,455)
Limited partners (390,196 (413,770
) )
-------- --------
---- ----
Total partners' equity (479,698 (506,225
) )
-------- --------
---- ----
$ 275,964 234,620
======= =======
Southwest Royalties Institutional Income Fund X-C, L.P.
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2004 2003
---- ----
Revenues
- -------------
Income from net profits $ 91,227 76,029
interests
Interest 43 52
Other 250 -
---------- ---------
-
91,520 76,081
---------- ---------
-
Expenses
- ------------
General and administrative 12,569 10,235
Depreciation, depletion and 3,000 12,000
amortization
Accretion of asset retirement 14,817 16,270
obligation
---------- ---------
-
30,386 38,505
---------- ---------
-
Net income from continued 61,134 37,576
operations
Results from discontinued
operations -
sale of oil and gas leases - See (4,607) 4,153
Note 4
---------- ---------
-
Net income before cumulative
effect
of accounting change 56,527 41,729
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See - (599,030)
Note 3
---------- ---------
-
Net income (loss) $ 56,527 (557,301)
====== ======
Net income (loss) allocated to:
Managing General Partner $ 5,357 (49,077)
====== ======
General partner $ 596 (5,453)
====== ======
Limited partners $ 50,574 (502,771)
====== ======
Per limited partner unit
before discontinued
operations and cumulative $ 9.15 5.45
effect
Discontinued operations per (.69) .61
limited partner unit
Cumulative effect per limited -
partner unit (90.11)
---------- ---------
-
Per limited partner unit $ 8.46 (84.05)
====== ======
Southwest Royalties Institutional Income Fund X-C, L.P.
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2004 2003
----- ----
Cash flows from operating
activities:
Cash received from net profits $ 43,443 48,364
interest
Cash paid to suppliers (11,506) (6,760)
Discontinued operations (4,607) 4,153
Interest received 43 52
Other 250 -
--------- ---------
- -
Net cash provided by operating 27,623 45,809
activities
--------- ---------
- -
Cash flows provided by investing
activities:
Sale of oil and gas properties - 7,000
--------- ---------
- -
Cash flows used in financing
activities:
Distributions to partners (30,000) (50,000)
--------- ---------
- -
Net (decrease) increase in cash (2,377) 2,809
and cash equivalents
Beginning of period 26,631 20,887
--------- ---------
- -
End of period $ 24,254 23,696
====== ======
Reconciliation of net income
(loss) to net cash
provided by operating
activities:
Net income (loss) $ 56,527 (557,301)
Adjustments to reconcile net
income (loss) to
net cash provided by operating
activities:
Depreciation, depletion and 3,000 12,000
amortization
Accretion of asset retirement 14,817 16,270
obligation
Cumulative effect of change in
accounting
principle - SFAS No. 143 - 599,030
Increase in receivables (47,784) (27,665)
Increase in payables 1,063 3,475
--------- ---------
- -
Net cash provided by operating $ 27,623 45,809
activities
====== ======
Noncash investing and financing
activities:
Increase in oil and gas
properties - Adoption
of SFAS No.143 $ - 214,465
====== ======
Southwest Royalties Institutional Income Fund X-C, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund X-C, L.P. was organized
under the laws of the state of Delaware on September 20, 1991, 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 several purchasers with the prices it receives being
dependent upon the oil and gas economy. Southwest Royalties, Inc.
serves as the Managing General Partner and H. H. Wommack, III, as the
individual general partner. Revenues, costs and expenses are
allocated as follows:
Limited General
Partners Partners
-------- --------
Interest income on 100% -
capital contributions
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and 100% -
offering costs (1)
Syndication costs 100% -
Amortization of 100% -
organization costs
Property acquisition 100% -
costs
Gain/loss on property 90% 10%
disposition
Operating and 90% 10%
administrative costs
(2)
Depreciation, depletion
and amortization
of oil and gas 100% -
properties
All other costs 90% 10%
(1) All organization costs in excess of 3% of initial capital
contributions will be paid by the Managing General Partner and
will be treated as a capital contribution. The Partnership paid
the Managing General Partner an amount equal to 3% of initial
capital contributions for such organization costs.
(2) Administrative costs in any year, which exceed 2% of capital
contributions shall be paid by the Managing General Partner and
will be treated as a capital contribution.
2. Summary of Significant Accounting Policies
The interim financial information as of March 31, 2004, and for the
three months ended March 31, 2004, is unaudited. Certain information
and footnote disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles
have been condensed or omitted in this Form 10-Q pursuant to the rules
and regulations of the Securities and Exchange Commission. However,
in the opinion of management, these interim financial statements
include all the necessary adjustments to fairly present the results of
the interim periods and all such adjustments are of a normal recurring
nature. The interim consolidated financial statements should be read
in conjunction with the Partnership's Annual Report on Form 10-K for
the year ended December 31, 2003.
Southwest Royalties Institutional Income Fund X-C, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
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 $214,465, a long term liability of
approximately $813,495 and a loss of approximately $599,030 for the
cumulative effect on depreciation of the additional costs and
accretion expense on the liability related to expected abandonment
costs of its oil and natural gas producing properties. At March 31,
2004, the asset retirement obligation was $755,662. The decrease in
the balance from January 1, 2004 is due to accretion expense of
$14,817.
4. Discontinued Operations - Sale of oil and gas leases
During 2003, the Partnership sold its interest in certain oil and gas
wells for $81,184 sales proceeds and retired $100,007 of asset
retirement obligation associated with the properties. Since the
Partnership is under the full cost pool method of accounting, the
sales proceeds and asset retirement obligation liability were taken
against the oil and gas properties asset account and therefore, no
gain or loss was recorded and shown on the statement of operations as
part of the discontinued operations. Operating expenses for 2004
represent plugging and abandonment costs that the Partnership was
contractually committed to perform prior to the sale of the property.
Plugging and abandonment services were performed during the quarter
ended March 31, 2004. Pursuant to the requirements of SFAS No. 144,
the operating results from these properties have been reported as
discontinued operations in the accompanying statements of operations.
The following table summarizes certain historical operating
information related to the discontinued operations:
Three months ended
March 31,
2004 2003
Income from net
profit
interest $(4,607) 4,153
5. Subsequent Event
Subsequent to December 31, 2003, the Managing General Partner
announced that its Board of Directors had decided to explore a merger
or sale of the stock of the Company. The Board formed a Special
Committee of independent directors to oversee the sale process. The
Special Committee retained independent financial and legal advisors to
work closely with management to implement the sale process.
On May 3, 2004, the Managing General Partner entered into a cash
merger agreement to sell all of its stock to Clayton Williams Energy,
Inc. The cash merger price is being negotiated, but is expected to be
approximately $45 per share. The transaction, which is subject to
approval by the Managing General Partner's shareholders, is expected
to close no later than May 21, 2004.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund X-C, L.P. was organized as a
Delaware limited partnership on September 20, 1991. The offering of such
limited partnership interests began October 1, 1991 as part of a shelf
offering registered under the name Southwest Royalties Institutional 1990-
91 Income Program. Minimum capital requirements for the Partnership were
met on January 28, 1992, with the offering of limited partnership interests
concluding April 30, 1992.
The Partnership was formed to acquire royalty and net profits interests in
producing oil and gas properties, to produce and market crude oil and
natural gas produced from such properties, and to distribute the net
proceeds from operations to the limited and general partners. Net revenues
from producing oil and gas properties will not be reinvested in other
revenue producing assets except to the extent that production facilities
and wells are improved or reworked or where methods are employed to improve
or enable more efficient recovery of oil and gas reserves. The economic
life of the Partnership thus depends on the period over which the
Partnership's oil and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore,
distributions to partners will depend primarily on changes in the prices
received for production, changes in volumes of production sold, lease
operating expenses, enhanced recovery projects, offset drilling activities
pursuant to farm-out arrangements, sales of properties, and the depletion
of wells. Since wells deplete over time, production can generally be
expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to decline in later years based on these factors.
Based on current conditions, management anticipates performing no workovers
during 2004 to enhance production. The partnership will most likely
continue to experience the historical production decline, which has
approximated 10% per year. Accordingly, if commodity prices remain
unchanged, the Partnership expects future earnings to decline due to
anticipated production declines.
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
sold.
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.
Should the net capitalized costs exceed the estimated present value of oil
and gas reserves, discounted at 10%, such excess costs would be charged to
current expense. As of March 31, 2004, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net
profits interests in proved properties located within the continental
United States. A net profits interest is created when the owner of a
working interest in a property enters into an arrangement providing that
the net profits interest owner will receive a stated percentage of the net
profit from the property. The net profits interest owner will not
otherwise participate in additional costs and expenses of the property.
The Partnership recognizes income from its net profits interest in oil and
gas property on an accrual basis, while the quarterly cash distributions of
the net profits interest are based on a calculation of actual cash received
from oil and gas sales, net of expenses incurred during that quarterly
period. If the net profits interest calculation results in expenses
incurred exceeding the oil and gas income received during a quarter, no
cash distribution is due to the Partnership's net profits interest until
the deficit is recovered from future net profits. The Partnership accrues
a quarterly loss on its net profits interest provided there is a cumulative
net amount due for accrued revenue as of the balance sheet date. As of
March 31, 2004, there were no timing differences, which resulted in a
deficit net profit interest.
Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost method
of accounting for its oil and gas properties. The full cost method
subjects companies to quarterly calculations of a "ceiling", or limitation
on the amount of properties that can be capitalized on the balance sheet.
If the Partnership's capitalized costs are in excess of the calculated
ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants. Quarterly reserve estimates
are prepared by the Managing General Partner's internal staff of engineers.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
In 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.
Results of Operations
A. General Comparison of the Quarters Ended March 31, 2004 and 2003
The following table provides certain information regarding performance
factors for the quarters ended March 31, 2004 and 2003.
Three Months
Ended Percenta
ge
March 31, Increase
2004 2003 (Decreas
e)
----- ----- --------
--
Average price per $ 31.03 -
barrel of oil 31.06
Average price per mcf $ 4.56 (12%)
of gas 5.21
Oil production in 5,710 6,390 (11%)
barrels
Gas production in mcf 5,800 5,470 6%
Income from net profits $ 91,227 76,029 20%
interests
Partnership $ 30,000 50,000 (40%)
distributions
Limited partner $ 27,000 45,000 (40%)
distributions
Per unit distribution
to limited
partners $ 4.51 (40%)
7.52
Number of limited 5,983 5,983
partner units
Revenues
The Partnership's income from net profits interests increased to $91,227
from $76,029 for the quarters ended March 31, 2004 and 2003, respectively,
an increase of 20%. The principal factors affecting the comparison of the
quarters ended March 31, 2004 and 2003 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the quarter ended March 31, 2004 as compared to the
quarter ended March 31, 2003 by less than 1%, or $.03 per barrel,
resulting in a decrease of approximately $200 in income from net
profits interests. Oil sales represented 87% of total oil and gas
sales during the quarter ended March 31, 2004 as compared to 87% during
the quarter ended March 31, 2003.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 12%, or $.65 per mcf, resulting in
a decrease of approximately $3,800 in income from net profits
interests.
The total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$4,000. 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.
2. Oil production decreased approximately 680 barrels or 11% during the
quarter ended March 31, 2004 as compared to the quarter ended March 31,
2003, resulting in a decrease of approximately $21,100 in income from
net profits interests.
Gas production increased approximately 330 mcf or 6% during the same
period, resulting in an increase of approximately $1,700 in income from
net profits interests.
The net total decrease in income from net profits interests due to the
change in production is approximately $19,400. The decrease in oil
volumes is due to production declines on two properties.
3. Lease operating costs and production taxes were 26% lower, or
approximately $38,700 less during the quarter ended March 31, 2004 as
compared to the quarter ended March 31, 2003. Lease operating expenses
were higher in 2003 as a result of electricity credits on one property
in 2004, plug and abandonment costs for a well in 2003 and replacing a
tank on a salt water disposal facility in 2003.
Costs and Expenses
Total costs and expenses decreased to $30,386 from $38,505 for the quarters
ended March 31, 2004 and 2003, respectively, a decrease of 21%. The
decrease is a direct result of the decrease in accretion expense associated
with our long term liability related to expected abandonment costs of our
oil and natural gas properties and depletion expense, partially offset by
an increase in general and administrative expense.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased
23% or approximately $2,300 during the quarter ended March 31, 2004 as
compared to the quarter ended March 31, 2003. The increase in general
and administrative costs is due primarily to an increase of
approximately $1,660 in quarterly accounting review fees.
2. Depletion expense decreased to $3,000 for the quarter ended March 31,
2004 from $12,000 for the same period in 2003. This represents a
decrease of 75%. The contributing factor to the decrease in depletion
expense is in relation to the BOE depletion rate for the quarter ended
March 31, 2004, which was $.45 applied to 6,677 BOE as compared to
$1.64 applied to 7,302 BOE for the same period in 2003.
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 $214,465, a long term liability of
approximately $813,495 and a loss of approximately $599,030 for the
cumulative effect on depreciation of the additional costs and accretion
expense on the liability related to expected abandonment costs of its oil
and natural gas producing properties. At March 31, 2004, the asset
retirement obligation was $755,662. The decrease in the balance from
January 1, 2004 is due to accretion expense of $14,817.
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 $27,600 in
the quarter ended March 31, 2004 as compared to approximately $45,800 in
the quarter ended March 31, 2003.
There were no cash flows used in investing activities in the quarter ended
March 31, 2004. Cash flows provided by investing activities were
approximately $7,000 in the quarter ended March 31, 2003.
Cash flows used in financing activities were approximately $30,000 in the
quarter ended March 31, 2004. Cash flows used in financing activities were
approximately $50,000 in the quarter ended March 31, 2003. The only use in
financing activities was the distributions to partners.
Total distributions during the quarter ended March 31, 2004 were $30,000 of
which $27,000 was distributed to the limited partners and $3,000 to the
general partners. The per unit distribution to limited partners during the
quarter ended March 31, 2004 was $4.51. Total distributions during the
quarter ended March 31, 2003 were $50,000 of which $45,000 was distributed
to the limited partners and $5,000 to the general partners. The per unit
distribution to limited partners during the quarter ended March 31, 2003
was $7.52.
The primary sources for the 2004 distributions of $30,000 were oil and gas
operations of approximately $27,600, with the balance from available cash
on hand at the beginning of the period. The primary sources for the 2003
distributions of $50,000 were oil and gas operations of approximately
$45,800 and the change in oil and gas properties of approximately $7,000,
resulting in excess cash for contingencies or subsequent distribution to
partners.
Cumulative cash distributions of $3,477,838 have been made to the general
and limited partners. As of March 31, 2004, $3,147,875 or $526.14 per
limited partner unit has been distributed to the limited partners,
representing a 100% return of capital and a 5% return on capital
contributed.
As of March 31, 2004, the Partnership had approximately $111,500 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.
Liquidity - Managing General Partner
As of December 31, 2003, the Managing General Partner is in violation of
several covenants pertaining to their Amended and Restated Revolving Credit
Agreement due June 1, 2006 and their Senior Second Lien Secured Credit
Agreement due October 15, 2008. Due to the covenant violations, the
Managing General Partner is in default under their Amended and Restated
Revolving Credit Agreement and the Senior Second Lien Secured Credit
Agreement, and all amounts due under these agreements have been classified
as a current liability on the Managing General Partner's balance sheet at
December 31, 2003. The significant working capital deficit and debt being
in default at December 31, 2003, raise substantial doubt about the Managing
General Partner's ability to continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the Managing
General Partner announced its decision to explore a merger, sale of the
stock or other transaction involving the Managing General Partner. The
Board has formed a Special Committee of independent directors to oversee
the sales process. The Special Committee has retained independent
financial and legal advisors to work closely with the management of the
Managing General Partner to implement the sales process. There can be no
assurance that a sale of the Managing General Partner will be consummated
or what terms, if consummated, the sale will be on.
On May 3, 2004, the Managing General Partner entered into a cash merger
agreement to sell all of its stock to Clayton Williams Energy, Inc. The
cash merger price is being negotiated, but is expected to be approximately
$45 per share. The transaction, which is subject to approval by the
Managing General Partner's shareholders, is expected to close no later than
May 21, 2004.
Recent Accounting Pronouncements
The EITF is considering two issues related to the reporting of oil and gas
mineral rights. Issue No. 03-O, "Whether Mineral Rights Are Tangible or
Intangible Assets," is whether or not mineral rights are intangible assets
pursuant to SFAS No. 141, "Business Combinations." Issue No. 03-S,
"Application of SFAS No. 142, Goodwill and Other Intangible Assets, to Oil
and Gas Companies," is, if oil and gas drilling rights are intangible
assets, whether those assets are subject to the classification and
disclosure provisions of SFAS No. 142. The Partnership classifies the cost
of oil and gas mineral rights as properties and equipment and believes that
this is consistent with oil and gas accounting and industry practice. The
disclosures required by SFAS Nos. 141 and 142 would be made in the notes to
the financial statements. There would be no effect on the statement of
income or cash flows as the intangible assets related to oil and gas
mineral rights would continue to be amortized under the full cost method of
accounting.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative
instruments.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
As of the three months ended March 31, 2004, H.H. Wommack, III, President
and Chief Executive Officer of the Managing General Partner, and Bill E.
Coggin, Executive Vice President and Chief Financial Officer of the
Managing General Partner, evaluated the effectiveness of the Partnership's
disclosure controls and procedures. Based on their evaluation, they
believe that:
The disclosure controls and procedures of the Partnership were
effective in ensuring that information required to be disclosed by the
Partnership in the reports it files or submits under the Exchange Act
was recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms; and
The disclosure controls and procedures of the Partnership were
effective in ensuring that material information required to be
disclosed by the Partnership in the report it filed or submitted under
the Exchange Act was accumulated and communicated to the Managing
General Partner's management, including its President and Chief
Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
There has not been any change in the Partnership's internal control over
financial reporting that occurred during the three months ended March 31,
2004 that has materially affected, or is reasonably likely to materially
affect, it internal control over financial reporting.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Certification of Chief Executive Officer Pursuant to 18
U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
32.2 Certification of Chief Financial Officer Pursuant to 18
U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter
for which this report is filed.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHWEST ROYALTIES INSTITUTIONAL
INCOME FUND X-C, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
---------------------------------------
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: May 14, 2004
SECTION 302 CERTIFICATION Exhibit 31.1
I, H.H. Wommack, III, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties Institutional Income Fund X-C, 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 15-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules 13a-
15(f) and 15d-15(f) 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)Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;
c)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
d)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 controls 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
controls over financial reporting.
Date: May 14, 2004 /s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive
Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income
Fund X-C, L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Bill E. Coggin, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties Institutional Income Fund X-C, 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 15-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules 13a-
15(f) and 15d-15(f) 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)Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;
c)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
d)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 controls 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
controls over financial reporting.
Date: May 14, 2004 /s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income
Fund X-C, L.P.
CERTIFICATION PURSUANT TO Exhibit 32.1
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Royalties
Institutional Income Fund X-C, L.P. (the "Company") on Form 10-Q for the
period ending March 31, 2004 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, H.H. Wommack, III, Chief
Executive Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition
and results of operation of the
Company.
Date: May 14, 2004
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund X-C, L.P.
CERTIFICATION PURSUANT TO Exhibit 32.2
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Royalties
Institutional Income Fund X-C, L.P. (the "Company") on Form 10-Q for the
period ending March 31, 2004 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, Bill E. Coggin, Chief
Financial Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition
and results of operation of the
Company.
Date: May 14, 2004
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties Institutional Income Fund X-C, L.P.