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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2005
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 0-15408
Southwest Royalties, Inc. Income Fund V
(Exact name of registrant as specified
in its limited partnership agreement)
Tennessee 75-2104619
(State or other jurisdiction of (I.R.S.
Employer
incorporation or organization)
Identification No.)
6 Desta Drive, Suite 6500
Midland, Texas, 79705
(Address of principal executive offices)
(432) 682-6324
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:
Yes X No ___
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 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.
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.
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 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. - 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, 2004, which are found in the Registrant's Form
10-K Report for 2004 filed with the Securities and Exchange Commission.
The December 31, 2004 balance sheet included herein has been taken from the
Registrant's 2004 Form 10-K Report. Operating results for the three and
nine-month periods ended September 30, 2005 are not necessarily indicative
of the results that may be expected for the full year.
Southwest Royalties, Inc. Income Fund V
Balance Sheets
Septemb December
er 30, 31,
2005 2004
------ ------
(unaudi
ted)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 108,136 29,725
Receivable from Managing General 17,070 90,993
Partner
Other 920 690
------- ---------
----- ---
Total current assets 126,126 121,408
------- ---------
----- ---
Oil and gas properties - using the
full-
cost method of accounting 6,199,7 6,216,644
63
Less accumulated depreciation,
depletion and amortization 5,678,5 5,664,406
22
------- ---------
----- ---
Net oil and gas properties 521,241 552,238
------- ---------
----- ---
$ 647,367 673,646
======= =======
Liabilities and Partners' Equity
- -------------------------------------
- ---
Current liability:
Distribution payable $ 333 87
------- ---------
----- ---
Asset retirement obligation 269,475 274,578
------- ---------
----- ---
Partners' equity (deficit):
General partner (637,60 (635,466)
8)
Limited partners 1,015,1 1,034,447
67
------- ---------
----- ---
Total partners' equity 377,559 398,981
------- ---------
----- ---
$ 647,367 673,646
======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties, Inc. Income Fund V
Statements of Operations
(unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2004 2005 2004
----- ----- ----- -----
Revenues
- -------------
Income from net profits $ 103,688 81,482 316,781 234,484
interests
Interest 275 56 493 187
Other - - - 247
--------- ------- ------- -------
--- ----- ----- -----
103,963 81,538 317,274 234,918
--------- ------- ------- -------
--- ----- ----- -----
Expenses
- ------------
Depreciation, depletion and 4,309 4,012 14,117 19,012
amortization
Accretion expense 3,926 5,104 11,778 15,311
General and administrative 30,281 31,544 92,801 95,135
--------- ------- ------- -------
--- ----- ----- -----
38,516 40,660 118,696 129,458
--------- ------- ------- -------
--- ----- ----- -----
Net income $ 65,447 40,878 198,578 105,460
======= ======= ======= =======
Net income allocated to:
Managing General Partner $ 6,545 4,088 19,858 10,546
======= ======= ======= =======
Limited Partners $ 58,902 36,790 178,720 94,914
======= ======= ======= =======
Per limited partner unit $ 7.85 23.83
4.91 12.66
======= ======= ======= =======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties, Inc. Income Fund V
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
2005 2004
----- -----
Cash flows from operating activities
Cash received from income from net
profits interests $ 390,473 228,199
Cash paid to suppliers (92,801 (95,135
) )
Interest received 493 187
Other - 247
------- -------
--- ---
Net cash provided by operating 298,165 133,498
activities
------- -------
--- ---
Cash flows used in financing activities
Distributions to partners (220,00 (145,00
0) 0)
Increase in distribution payable 246 236
------- -------
--- ---
Net cash used in financing activities (219,75 (144,76
4) 4)
------- -------
--- ---
Net increase (decrease) in cash and 78,411 (11,266
cash equivalents )
Beginning of period 29,725 42,849
------- -------
--- ---
End of period $ 108,136 31,583
====== ======
Reconciliation of net income to net cash
provided by operating activities
Net income $ 198,578 105,460
Adjustments to reconcile net income to
net
cash provided by operating activities
Depreciation, depletion and amortization 14,117 19,012
Accretion expense 11,778 15,311
Decrease (increase) in receivables 73,692 (6,285)
------- -------
--- ---
Net cash provided by operating activities $ 298,165 133,498
====== ======
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties, Inc. Income Fund V
(a Tennessee limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties, Inc. Income Fund V was organized under the laws
of the state of Tennessee on May 1, 1986, 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 90% 10%
All other costs 90% 10%
(1) All organization costs in excess of 3% of initial capital
contributions will be paid by the Managing General Partner and
will be treated as a capital contribution. The Partnership paid
the Managing General Partner an amount equal to 3% of initial
capital contributions for such organization costs.
(2) Administrative costs in any year, which exceed 2% of capital
contributions shall be paid by the Managing General Partner and
will be treated as a capital contribution.
2. Summary of Significant Accounting Policies
The interim financial information as of September 30, 2005, and for
the three and nine months ended September 30, 2005, 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, 2004.
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 are 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
implementation of SAB 106 did not have a material impact on our
financial statements.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties, Inc. Income Fund V was organized as a Tennessee
limited partnership on May 1, 1986, after receipt from investors of
$1,000,000 in limited partner capital contributions. The offering of
limited partnership interests began on January 22, 1986 and concluded on
July 22, 1986, with total limited partner contributions of $7,500,000.
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 are not reinvested in other revenue
producing assets except to the extent that production facilities and wells
are improved or reworked or where methods are employed to improve or enable
more efficient recovery of oil and gas reserves. The economic life of the
Partnership thus depends on the period over which the Partnership's oil and
gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore,
distributions to partners will depend primarily on changes in the prices
received for production, changes in volumes of production sold, increases
and decreases in lease operating expenses, enhanced recovery projects,
offset drilling activities pursuant to 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 fluctuate in later years based on these factors.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
sold.
Should the net capitalized costs exceed the estimated present value of oil
and gas reserves, discounted at 10%, such excess costs would be charged to
current expense. As of September 30, 2005, 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
September 30, 2005, there were no timing differences, which resulted in a
deficit net profit interest.
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 Quarters Ended September 30, 2005 and 2004
The following table provides certain information regarding performance
factors for the quarters ended September 30, 2005 and 2004:
Three Months
Ended Percenta
ge
September 30, Increase
2005 2004 (Decreas
e)
----- ----- --------
--
Oil production in barrels 2,264 2,193 3%
Gas production in mcf 17,092 18,697 (9%)
Total BOE 5,113 5,309 (4%)
Average price per barrel of $ 63.43 50%
oil 42.19
Average price per mcf of gas $ 8.10 40%
5.78
Income from net profits $ 103,688 81,482 27%
interests
Partnership distributions $ 80,000 55,000 45%
Limited partner $ 72,000 49,500 45%
distributions
Per unit distribution to $ 9.60 45%
limited partners 6.60
Number of limited partner 7,499 7,499
units
Income from net profits
The Partnership's income from net profits interests increased to $103,688
from $81,482 for the quarters ended September 30, 2005 and 2004,
respectively, an increase of 27%. The principal factors affecting the
comparison of the quarters ended September 30, 2005 and 2004 are as
follows:
The average price for a barrel of oil received by the Partnership increased
during the quarter ended September 30, 2005 as compared to the quarter
ended September 30, 2004 by 50%, or $21.24 per barrel, resulting in an
increase of approximately $48,100 in income from net profits interests.
Oil sales represented 51% of total oil and gas sales during the quarter
ended September 30, 2005 as compared to 46% during the quarter ended
September 30, 2004.
The average price for an mcf of gas received by the Partnership increased
during the same period by 40%, or $2.32 per mcf, resulting in an increase
of approximately $39,700 in income from net profits interests.
The total increase in income from net profits interests due to the change
in prices received from oil and gas production is approximately $87,800.
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 increased approximately 71 barrels or 3% during the quarter
ended September 30, 2005 as compared to the quarter ended September 30,
2004, resulting in an increase of approximately $3,000 in income from net
profits interests.
Gas production decreased approximately 1,605 mcf or 9% during the same
period, resulting in a decrease of approximately $9,300 in income from net
profits interests.
The net total decrease in income from net profits interests due to the
change in production is approximately $6,300.
Lease operating costs and production taxes were 50% higher, or
approximately $59,200 more during the quarter ended September 30, 2005 as
compared to the quarter ended September 30, 2004. The increase in lease
operating costs is primarily from well repairs on a salt water disposal
well and surface repairs on a producing property.
Costs and Expenses
Total costs and expenses decreased to $38,516 from $40,660 for the quarters
ended September 30, 2005 and 2004, respectively, a decrease of 5%. The
decrease is the result of lower general and administrative expense and
accretion expense, partially offset by an increase in depletion expense.
General and administrative costs consists of independent accounting, legal
and engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased 4% or
approximately $1,300 during the quarter ended September 30, 2005 as
compared to the quarter ended September 30, 2004.
Depletion expense increased to $4,309 for the quarter ended September 30,
2005 from $4,012 for the same period in 2004. This represents an increase
of 7%. The contributing factor to the increase in depletion rate is in
relation to the BOE depletion rate for the quarter ended September 30, 2005
was $.84 applied to 5,113 BOE compared to $.76 applied to 5,309 BOE for the
same period in 2004.
Accretion expense decreased to $3,926 for the quarter ended September 30,
2005 from $5,104 for the same period in 2004. This represents a decrease
of 23%. The decrease in accretion is from discontinuing accretion on
several wells that reached their projected end of life in 2004.
General Comparison of the Nine-Month Periods Ended September 30, 2005 and
2004
The following table provides certain information regarding performance
factors for the nine-month periods ended September 30, 2005 and 2004:
Nine Months
Ended Percenta
ge
September 30, Increase
2005 2004 (Decreas
e)
----- ----- --------
--
Oil production in barrels 7,288 7,003 4%
Gas production in mcf 49,464 51,367 (4%)
Total BOE 15,532 15,564 -
Average price per barrel of $ 54.55 46%
oil 37.29
Average price per mcf of gas $ 7.06 18%
5.96
Income from net profits $ 316,781 234,484 35%
interests
Partnership distributions $ 220,000 145,000 52%
Limited partner $ 198,000 130,500 52%
distributions
Per unit distribution to
limited
partners $ 26.40 52%
17.40
Number of limited partner 7,499 7,499
units
Income from net profits
The Partnership's income from net profits interests increased to $316,781
from $234,484 for the nine months ended September 30, 2005 and 2004,
respectively, an increase of 35%. The principal factors affecting the
comparison of the nine months ended September 30, 2005 and 2004 are as
follows:
The average price for a barrel of oil received by the Partnership increased
during the nine months ended September 30, 2005 as compared to the nine
months ended September 30, 2004 by 46%, or $17.26 per barrel, resulting in
an increase of approximately $125,800 in income from net profits interests.
Oil sales represented 53% of total oil and gas sales during the nine months
ended September 30, 2005 as compared to 46% during the nine months ended
September 30, 2004.
The average price for an mcf of gas received by the Partnership increased
during the same period by 18%, or $1.10 per mcf, resulting in an increase
of approximately $54,400 in income from net profits interests.
The total increase in income from net profits interests due to the change
in prices received from oil and gas production is approximately $180,200.
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 increased approximately 285 barrels or 4% during the nine
months ended September 30, 2005 as compared to the nine months ended
September 30, 2004, resulting in an increase of approximately $10,600 in
income from net profits interests.
Gas production decreased approximately 1,903 mcf or 4% during the same
period, resulting in a decrease of approximately $11,300 in income from net
profits interests.
The net total decrease in income from net profits interests due to the
change in production is approximately $700.
Lease operating costs and production taxes were 29% higher, or
approximately $96,800 more during the nine months ended September 30, 2005
as compared to the nine months ended September 30, 2004. The increase in
lease operating costs is primarily from well repairs on a saltwater
disposal well and surface repairs on a producing property.
Costs and Expenses
Total costs and expenses decreased to $118,696 from $129,458 for the nine
months ended September 30, 2005 and 2004, respectively, a decrease of 8%.
The decrease is the result of lower general and administrative expense,
depletion expense and accretion expense.
General and administrative costs consists of independent accounting, legal
and engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased 2% or
approximately $2,300 during the nine months ended September 30, 2005 as
compared to the nine months ended September 30, 2004.
Depletion expense decreased to $14,117 for the nine months ended September
30, 2005 from $19,012 for the same period in 2004. This represents a
decrease of 26%. The contributing factor to the decrease in depletion
expense is in relation to the BOE depletion rate for the nine months ended
September 30, 2005, which was $.91 applied to 15,532 BOE as compared to
$1.22 applied to 15,564 BOE for the same period in 2004. The lower
depletion rate in 2005 is due to the upward revision in reserve estimates
resulting from higher oil and gas prices.
Accretion expense decreased to $11,778 for the nine months ended September
30, 2005 from $15,311 for the same period in 2004. This represents a
decrease of 23%. The decrease in accretion is from discontinuing accretion
on several wells that reached their projected end of life in 2004.
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 $298,200 in
the nine months ended September 30, 2005 as compared to approximately
$133,500 in the nine months ended September 30, 2004.
Cash flows used in financing activities were approximately $219,800 in the
nine months ended September 30, 2005 as compared to approximately $144,800
in the nine months ended September 30, 2004. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 2005 were
$220,000 of which $198,000 was distributed to the limited partners and
$22,000 to the general partners. The per unit distribution to limited
partners during the nine months ended September 30, 2005 was $26.40. Total
distributions during the nine months ended September 30, 2004 were $145,000
of which $130,500 was distributed to the limited partners and $14,500 to
the general partners. The per unit distribution to limited partners during
the nine months ended September 30, 2004 was $17.40.
The source for the 2005 distributions of $220,000 was oil and gas
operations of approximately $298,200, resulting in excess cash for
contingencies or subsequent distributions. The source for the 2004
distributions of $145,000 was oil and gas operations of approximately
$133,500, with the balance from available cash on hand at the beginning of
the period.
Cumulative cash distributions of $8,346,841 have been made to the partners.
As of September 30, 2005, $7,496,618 or $999.68 per limited partner unit
has been distributed to the limited partners, representing a 100% return of
the capital contributed.
As of September 30, 2005, the Partnership had approximately $125,800 in
working capital. The Managing General Partner knows of no unusual
contractual commitments. The partnership held many long-lived properties
at inception, however due to the restrictions on property development
imposed by the partnership agreement, the Partnership cannot develop its
non-producing properties. Without continued development, the producing
reserves continue to deplete. Accordingly, as the Partnership's properties
have matured and depleted, the net cash flows from operations for the
partnership has steadily declined, except in periods of substantially
increased commodity pricing. Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production. As the
properties continue to deplete, maintenance of properties and
administrative costs as a percentage of production are expected to continue
to increase.
Recent Accounting Pronouncements
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 are 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 implementation of SAB 106 did not have a material impact on
our financial statements.
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
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 September 30,
2005 that has materially affected, or is reasonably likely to materially
affect, its 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
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 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, Inc. Income Fund V, a
Tennessee limited partnership
By: Southwest Royalties, Inc., Managing
General Partner
By: /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
Date: November 14, 2005
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1.I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties, Inc. Income Fund V,
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: November 14, 2005 /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund V
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southwest
Royalties, Inc. Income Fund V,
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: November 14, 2005 /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund V
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-Q for the period ended September 30, 2005 that is being filed
concurrently with the Securities and Exchange Commission on the date hereof
(the "Report"), each of the undersigned officers of Southwest Royalties,
Inc. Income Fund V (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 Royalties, Inc. Income
Fund V
November 14, 2005
/s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income
Fund V
November 14, 2005