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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 June 30, 2002
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission File Number 33-38511
SOUTHWEST DEVELOPMENTAL DRILLING PROGRAM 1991-92
Southwest Developmental Drilling Fund 91-A, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2387814
(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)
(915) 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
The total number of pages contained in this report is 16.
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, 2001 which are found in the Registrant's Form
10-K Report for 2001 filed with the Securities and Exchange Commission.
The December 31, 2001 balance sheet included herein has been taken from the
Registrant's 2001 Form 10-K Report. Operating results for the three and
six month periods ended June 30, 2002 are not necessarily indicative of the
results that may be expected for the full year.
Southwest Developmental Drilling Fund 91-A, L.P.
Balance Sheets
June 30, December 31,
2002 2001
--------- ------------
(unaudited)
Assets
------
Current assets:
Cash and cash equivalents $ 8,714 12,402
Receivable from Managing General Partner 10,506 2,047
- --------- ---------
Total current assets
19,220 14,449
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 1,098,776 1,098,776
Less accumulated depreciation,
depletion and amortization
986,000 980,000
- --------- ---------
Net oil and gas properties
112,776 118,776
- --------- ---------
$
131,996 133,225
========= =========
Liabilities and Partners' Equity
--------------------------------
Current liability - Distribution payable $ - 39
- --------- ---------
Partners' equity:
Managing General Partner 23,042 22,513
Investor partners 108,954 110,673
- --------- ---------
Total partners' equity
131,996 133,186
- --------- ---------
$
131,996 133,225
========= =========
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
----- ----- ----- -----
Revenues
--------
Oil and gas $ 31,743 23,540 50,218 79,022
Interest 1 54 3 112
------- ------- ------- -------
31,744 23,594 50,221 79,134
------- ------- ------- -------
Expenses
--------
Production 13,128 24,509 27,571 38,787
General and administrative 3,940 3,829 7,840 7,659
Depreciation, depletion and
amortization 4,000 4,000 6,000 9,000
------- ------- ------- -------
21,068 32,338 41,411 55,446
------- ------- ------- -------
Net income (loss) $ 10,676 (8,744) 8,810 23,688
======= ======= ======= =======
Net income (loss) allocated to:
Managing General Partner $ 1,614 (522) 1,629 3,596
======= ======= ======= =======
Investor partners $ 9,062 (8,222) 7,181 20,092
======= ======= ======= =======
Per investor partner unit $ 7.92 (7.18) 6.27 17.56
======= ======= ======= =======
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Cash Flows
(unaudited)
Six Months Ended
June 30,
2002 2001
----- -----
Cash flows from operating activities:
Cash received from oil and gas sales $ 44,242 89,420
Cash paid to suppliers (37,894) (52,363)
Interest received 3 112
------- --------
Net cash provided by operating activities 6,351 37,169
------- --------
Cash flows used in financing activities:
Distributions to partners (10,039) (42,452)
------- --------
Net decrease in cash and cash equivalents (3,688) (5,283)
Beginning of period 12,402 14,338
------- --------
End of period $ 8,714 9,055
======= ========
Reconciliation of net income to net
cash provided by operating activities:
Net income $ 8,810 23,688
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 6,000 9,000
(Increase) decrease in receivables (5,976) 10,398
Decrease in payables (2,483) (5,917)
------- -------
Net cash provided by operating activities $ 6,351 37,169
======= =======
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 91-A, L.P. was organized under
the laws of the state of Delaware on January 7, 1991 for the purpose
of drilling developmental and exploratory wells 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. serves as the Managing General Partner. Revenues, costs and
expenses are allocated as follows:
Managing
General Investor
Partner Partners
-------- --------
Interest income on capital contributions - 100%
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and offering costs (1) - 100%
Syndication costs - 100%
Amortization of organization costs - 100%
Lease acquisition costs 1% 99%
Gain/loss on property disposition* 11% 89%
Operating and administrative costs*(2) 11% 89%
Depreciation, depletion and amortization
of oil and gas properties - 100%
Intangible drilling and development costs - 100%
All other costs* 11% 89%
*After the Investor Partners have received distributions totaling 150%
of their capital contributions, the allocation will change to 15%
Managing General Partner and 85% Investor Partners.
(1) All organization costs in excess of 4% 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 4% 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 June 30, 2002, and for the
three and six months ended June 30, 2002, 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 audited financial
statements for the year ended December 31, 2001.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 91-A, L.P. was organized as a
Delaware limited partnership on January 7, 1991. The offering of such
limited and general partner interests began September 17, 1991 as part of a
shelf offering registered under the name Southwest Developmental Drilling
Program 1991-92. Minimum capital requirements for the partnership were met
on April 22, 1992, with the offering of limited and general partner
interests concluding April 30, 1992, with total investor partner
contributions of $1,144,500. The Managing General Partner made a
contribution to the capital of the Partnership at the conclusion of its
offering period in an amount equal to 1% of its net capital contributions.
The Managing General Partner's contribution was $9,800. The total capital
contributions are $1,154,300.
The Partnership was formed to engage primarily in the business of drilling
developmental and exploratory wells, to produce and market crude oil and
natural gas produced from such properties, to distribute any net proceeds
from operations to the general and investor partners and to the extent
necessary, acquire leases which contain drilling prospects. Net revenues
will not be reinvested in other revenue producing assets except to the
extent that performance of remedial work is needed to improve a well's
producing capabilities. The economic life of the Partnership thus depends
on the period over which the Partnership's oil and gas reserves are
economically recoverable.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management anticipates performing no workovers
during 2002 to enhance production. The partnership will most likely
experience the historical production decline of approximately 8% per year.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
involved.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
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 June 30, 2002, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
Under the units of revenue method, the Partnership computes the provision
by multiplying the total unamortized cost of oil and gas properties by an
overall rate determined by dividing (a) oil and gas revenues during the
period by (b) the total future gross oil and gas revenues as estimated by
the Partnership's independent petroleum consultants. It is reasonably
possible that those estimates of anticipated future gross revenues, the
remaining estimated economic life of the product, or both could be changed
significantly in the near term due to the potential fluctuation of oil and
gas prices or production. The depletion estimate would also be affected by
this change.
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.
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.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
Results of Operations
A. General Comparison of the Quarters Ended June 30, 2002 and 2001
The following table provides certain information regarding performance
factors for the quarters ended June 30, 2002 and 2001:
Three Months
Ended Percentage
June 30, Increase
2002 2001 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 24.37 27.05 (10%)
Average price per mcf of gas $ 2.92 4.22 (31%)
Oil production in barrels 1,180 1,110 6%
Gas production in mcf 1,020 1,340 (24%)
Gross oil and gas revenue $ 31,743 23,540 35%
Net oil and gas revenue $ 18,615 (969) 2021%
Partnership distributions $ 10,000 12,500 (20%)
Investor partner distributions $ 8,900 11,125 (20%)
Per unit distribution to investor
partners $ 7.78 9.72 (20%)
Number of investor partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues increased to $31,743 from $23,540
for the quarters ended June 30, 2002 and 2001, respectively, an increase of
35%. The principal factors affecting the comparison of the quarters ended
June 30, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the quarter ended June 30, 2002 as compared to the
quarter ended June 30, 2001 by 10%, or $2.68 per barrel, resulting in a
decrease of approximately $3,200 in revenues. Oil sales represented
91% of total oil and gas sales during the quarter ended June 30, 2002
as compared to 84% during the quarter ended June 30, 2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 31%, or $1.30 per mcf, resulting in
a decrease of approximately $1,300 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $4,500. 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 increased approximately 70 barrels or 6% during the
quarter ended June 30, 2002 as compared to the quarter ended June 30,
2001, resulting in an increase of approximately $1,900 in revenues.
Gas production decreased approximately 320 mcf or 24% during the same
period, resulting in a decrease of approximately $1,400 in revenues.
The net total increase in revenues due to the change in production is
approximately $500. The decrease in gas production is due primarily to
downtime on one lease in addition to one lease that fluctuates levels
of production.
Costs and Expenses
Total costs and expenses decreased to $21,068 from $32,338 for the quarters
ended June 30, 2002 and 2001, respectively, a decrease of 35%. The
decrease is the result of lower lease operating costs, partially offset by
an increase in general and administrative expense.
1. Lease operating costs and production taxes were 46% lower, or
approximately $11,400 less during the quarter ended June 30, 2002 as
compared to the quarter ended June 30, 2001. The decrease in lease
operating expense is due to one lease having successful repairs and
maintenance performed in the quarter ended June 30, 2001.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 3%
or approximately $100 during the quarter ended June 30, 2002 as
compared to the quarter ended June 30, 2001.
3. Depletion expense remained the same for the quarter ended June 30, 2002
from the same period in 2001. Depletion is calculated using the units
of revenue method of amortization based on a percentage of current
period gross revenues to total future gross oil and gas revenues, as
estimated by the Partnership's independent petroleum consultants.
B. General Comparison of the Six Month Periods Ended June 30, 2002 and
2001
The following table provides certain information regarding performance
factors for the six month periods ended June 30, 2002 and 2001:
Six Months
Ended Percentage
June 30, Increase
2002 2001 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 22.43 27.71 (19%)
Average price per mcf of gas $ 2.45 5.27 (54%)
Oil production in barrels 2,040 2,260 (10%)
Gas production in mcf 1,820 3,110 (41%)
Gross oil and gas revenue $ 50,218 79,022 (36%)
Net oil and gas revenue $ 22,647 40,235 (44%)
Partnership distributions $ 10,000 42,500 (76%)
Investor partner distributions $ 8,900 37,825 (76%)
Per unit distribution to investor
partners $ 7.78 33.05 (76%)
Number of investor partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $50,218 from $79,022
for the six months ended June 30, 2002 and 2001, respectively, a decrease
of 36%. The principal factors affecting the comparison of the six months
ended June 30, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the six months ended June 30, 2002 as compared to the
six months ended June 30, 2001 by 19%, or $5.28 per barrel, resulting
in a decrease of approximately $10,800 in revenues. Oil sales
represented 91% of total oil and gas sales during the six months ended
June 30, 2002 as compared to 79% during the six months ended June 30,
2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 54%, or $2.82 per mcf, resulting in
a decrease of approximately $5,100 in revenues.
The total decrease in revenues due to the change in prices received
from oil and gas production is approximately $15,900. 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 220 barrels or 10% during the
six months ended June 30, 2002 as compared to the six months ended June
30, 2001, resulting in a decrease of approximately $6,100 in revenues.
Gas production decreased approximately 1,290 mcf or 41% during the same
period, resulting in a decrease of approximately $6,800 in revenues.
The total decrease in revenues due to the change in production is
approximately $12,900. The decrease in gas production is due primarily
to downtime on one lease in addition to one lease that fluctuates
levels of production.
Costs and Expenses
Total costs and expenses decreased to $41,411 from $55,446 for the six
months ended June 30, 2002 and 2001, respectively, a decrease of 25%. The
decrease is primarily the result of lower lease operating costs and
depletion expense partially offset by an increase in general and
administrative expense.
1. Lease operating costs and production taxes were 29% lower, or
approximately $11,200 less during the six months ended June 30, 2002 as
compared to the six months ended June 30, 2001. The decrease in lease
operating expense is due to one lease having repairs and maintenance
performed during 2001.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs increased 2%
or approximately $200 during the six months ended June 30, 2002 as
compared to the six months ended June 30, 2001.
3. Depletion expense decreased to $6,000 for the six months ended June 30,
2002 from $9,000 for the same period in 2001. This represents a
decrease of 33%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants. The contributing
factor to the decrease in depletion expense between the comparative
periods was the decrease in oil and gas revenues received by the
Partnership during 2002 as compared to 2001.
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 $6,400 in
the six months ended June 30, 2002 as compared to approximately $37,200 in
the six months ended June 30, 2001. The primary source of the 2002 cash
flow from operating activities was profitable operations.
Cash flows used in financing activities were approximately $10,000 in the
six months ended June 30, 2002 as compared to approximately $42,500 in the
six months ended June 30, 2001. The only use in financing activities was
the distributions to partners.
Total distributions during the six months ended June 30, 2002 were $10,000
of which $8,900 was distributed to the investor partners and $1,100 to the
Managing General Partner. The per unit distribution to investor partners
during the six months ended June 30, 2002 was $7.78. Total distributions
during the six months ended June 30, 2001 were $42,500 of which $37,825 was
distributed to the investor partners and $4,675 to the Managing General
Partner. The per unit distribution to investor partners during the six
months ended June 30, 2001 was $33.05.
The source for the 2002 distributions of $10,000 was oil and gas operations
of approximately $6,400, with the balance from available cash on hand at
the beginning of the period. The source for the 2001 distributions of
$42,500 was oil and gas operations of approximately $37,200, with the
balance from available cash on hand at the beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,406,009 have been made to the partners. As of June 30, 2002,
$1,253,259 or $1,095.03 per investor partner unit has been distributed to
the investor partners, representing a 110% return of the capital
contributed.
As of June 30, 2002, the Partnership had approximately $19,200 in working
capital. The Managing General Partner knows of no unusual contractual
commitments and believes the revenues generated from operations are
adequate to meet the needs of the Partnership.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged. The Managing General Partner is currently assessing the impact
on the partnerships financial statements.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets." This pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed" and eliminates the requirement of
Statement 121 to allocate goodwill to long-lived assets to be tested for
impairment. The provisions of this statement are effective for financial
statements issued for fiscal years beginning after December 15, 2001, and
interim periods within those fiscal years. The Managing General Partner
believes that the impact from SFAS No. 144 on the Partnerships financial
position and results of operation should not be significantly different
from that of SFAS No. 121.
In April 2002, FASB issued SFAS No. 145, "Rescission of SFAS No. 4,
44, and 64, Amendment of SFAS No. 13, and Technical Corrections." This
Statement rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt", and an amendment of that Statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements". This
Statement also rescinds or amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings, or
describe their applicability under changed conditions. This standard is
effective for fiscal years beginning after May 15, 2002. The Managing
General Partner believes that the adoption of this statement will not have
a significant impact on the Partnerships financial statements.
In July 2002, FASB issued SFAS No. 146 "Accounting for Costs
Associated with Exit or Disposal Activities" which establishes requirements
for financial accounting and reporting for costs associated with exit or
disposal activities. This standard is effective for exit or disposal
activities initiated after December 31, 2002. The Managing General Partner
is currently assessing the impact of this statement on the Partnerships'
future financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any
derivative or embedded derivative instruments.
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) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended
June 30, 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 DEVELOPMENTAL
DRILLING FUND 91-A, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
------------------------------
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: August 14, 2002