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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTER ENDED MARCH 31, 2000 COMMISSION FILE NO. 0-20998
KELLEY PARTNERS 1992 DEVELOPMENT
DRILLING PROGRAM
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0373428
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
601 JEFFERSON ST.
SUITE 1100
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200
Indicate by check mark whether the 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
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KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
INDEX
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION PAGE
----
<S> <C>
Balance Sheets as of December 31, 1999 and March 31, 2000 (unaudited)................................. 2
Statements of Income for the three months ended March 31, 1999 (unaudited) and 2000 (unaudited)....... 3
Statements of Cash Flows for the three months ended March 31, 1999 (unaudited) and 2000 (unaudited)... 4
Notes to Financial Statements (unaudited)............................................................. 5
Management's Discussion and Analysis of Financial Condition and Results of Operations................. 6
PART II. OTHER INFORMATION................................................................................. 9
</TABLE>
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1999 2000
----------- -----------
(UNAUDITED)
<S> <C> <C>
ASSETS:
Cash and cash equivalents .................................... $ -- $ --
Accounts receivable - trade .................................. 28 37
Accounts receivable - affiliates ............................. 17 188
----------- -----------
Total current assets ......................................... 45 225
----------- -----------
Oil and gas properties, successful efforts method:
Properties subject to amortization ......................... 41,466 41,409
Less: Accumulated depreciation, depletion & amortization .. (40,396) (40,429)
----------- -----------
Total oil and gas properties .................................... 1,070 980
----------- -----------
Total assets ............................................... $ 1,115 $ 1,205
=========== ===========
LIABILITIES:
Accounts payable and accrued expenses ........................ $ 62 $ 78
----------- -----------
Total current liabilities .................................... 62 78
----------- -----------
Long term note payable - affiliate ........................... 166 183
----------- -----------
Total liabilities ............................................ 228 261
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PARTNERS' EQUITY:
LP Unitholders' equity ....................................... 62 68
GP Unitholders' equity ....................................... 789 837
Managing and special general partners' equity ................ 36 39
----------- -----------
Total partners' equity ....................................... 887 944
----------- -----------
Total liabilities and partners' equity ..................... $ 1,115 $ 1,205
=========== ===========
</TABLE>
See Notes to Financial Statements (unaudited).
2
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KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
1999 2000
----------- -----------
<S> <C> <C>
REVENUES:
Oil and gas sales ........................... $ 334 $ 171
----------- -----------
Total revenues .............................. 334 171
----------- -----------
COSTS AND EXPENSES:
Lease operating expenses .................... 116 54
Severance taxes ............................. 17 4
General and administrative expenses ......... 32 18
Interest expense ............................ 64 5
Depreciation, depletion and amortization .... 101 33
----------- -----------
Total expenses .............................. 330 114
----------- -----------
Net income ..................................... $ 4 $ 57
=========== ===========
Net income allocable to LP and GP Unitholders .. $ 3 $ 55
=========== ===========
Net income allocable to managing and
special general partners .................... $ 1 $ 2
=========== ===========
Net income per LP and GP Unit .................. $ -- $ --
=========== ===========
Average LP and GP Units outstanding ............ 16,033 16,033
=========== ===========
</TABLE>
See Notes to Financial Statements (unaudited).
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KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
1999 2000
------------ ------------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income ...................................................... $ 4 $ 57
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ...................... 101 33
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable .................... 108 (180)
(Decrease) increase in accounts payable and accrued expenses .. (37) 16
------------ ------------
Net cash provided by (used in) operating activities ............. 176 (74)
------------ ------------
INVESTING ACTIVITIES:
Capital expenditures ............................................ (23) 57
------------ ------------
Net cash (used in) provided by investing activities ............. (23) 57
------------ ------------
FINANCING ACTIVITIES:
Principal (payments on) additions to long-term borrowings ....... (153) 17
------------ ------------
Net cash (used in) provided by financing activities ............. (153) 17
------------ ------------
Increase (decrease) in cash and cash equivalents ................... -- --
Cash and cash equivalents, beginning of period ..................... -- --
------------ ------------
Cash and cash equivalents, end of period ........................... $ -- $ --
============ ============
</TABLE>
See Notes to Financial Statements (unaudited).
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KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - BASIS OF PRESENTATION
General. The accompanying unaudited interim financial statements of
Kelley Partners 1992 Development Drilling Program (the "Partnership") have been
prepared pursuant to the rules and regulations of the Securities and Exchange
Commission in accordance with generally accepted accounting principles for
interim financial information. These financial statements reflect all
adjustments (consisting solely of normal recurring adjustments) necessary for a
fair statement of the results for the interim periods presented. The results of
operations for the period ended March 31, 2000 are not necessarily indicative of
results to be expected for the full year. The accounting policies followed by
the Partnership are set forth in Note 2 to the financial statements included in
its Annual Report on Form 10-K for the year ended December 31, 1999. These
unaudited interim financial statements should be read in conjunction with the
audited financial statements and notes thereto included in the Partnership's
1999 Annual Report on Form 10-K.
Derivative and Hedge Accounting. In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
which was amended in June 1999 by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133 - an amendment of FASB Statement No. 133." SFAS No. 133, as
amended, is effective for fiscal years beginning after June 15, 2000, and
establishes accounting and reporting standards for derivative instruments and
hedging activities that require an entity to recognize all derivatives as an
asset or liability measured at its fair value. Depending on the intended use of
the derivative, changes in its fair value will be reported in the period of
change as either a component of earnings or a component of other comprehensive
income. Retroactive application to periods prior to adoption is not allowed. The
Partnership has not quantified the impact of adoption on its financial
statements.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
In 1992, Kelley Partners 1992 Development Drilling Program (the
"Partnership") issued units of limited and general partner interests ("Units").
The Units represent 96.04% of the total interests in the Partnership. In
addition, the Partnership issued managing and special general partner interests
representing 3.96% of the total interests in the Partnership. Kelley Oil
Corporation, managing general partner of the Partnership ("Kelley Oil") and a
wholly owned subsidiary of Contour Energy Co. ("Contour") owns 83.72% of the
Units, together with its 3.94% managing general partnership interest.
RECENT DEVELOPMENTS
Drilling Operations. Since inception, the Partnership participated in
drilling 39 gross (15.23 net) wells, of which 30 gross (11.07 net) wells were
found productive and 9 gross (4.16 net) wells were dry.
Hedging Activities. Contour has periodically used forward sales
contracts, natural gas and crude oil swap agreements, natural gas basis swap
agreements and options to reduce exposure to downward price fluctuations on its
natural gas and crude oil production. Contour's hedging activities also cover
the natural gas and crude oil production attributable to the interest in such
production of the public unitholders in its subsidiary partnerships. The credit
risk exposure from counterparty nonperformance on natural gas forward sales
contracts and derivative financial instruments is generally the amount of
unrealized gains under the contracts. Contour has not experienced counterparty
nonperformance on these agreements and does not anticipate any in future
periods.
Through natural gas price swap agreements, approximately 66% and 49%
of the Partnership's natural gas production for the three months ended March 31,
1999 and March 31, 2000, respectively, was affected by hedging transactions at
average NYMEX quoted prices of $2.27 per Mmbtu and $2.48 per Mmbtu before
transaction and transportation costs. As of March 31, 2000, approximately 45% of
the Partnership's anticipated natural gas production for the remainder of 2000
had been hedged by natural gas price swap agreements at an average NYMEX quoted
price of $2.60 per Mmbtu before transaction and transportation costs. Through
crude oil price swap agreements, the Partnership hedged approximately 67% of its
crude oil production for the three months ended March 31, 2000, at an average
NYMEX quoted price of $25.09 per bbl, before transaction and transportation
costs. No crude oil was hedged in the three months ended March 31, 1999. As of
March 31, 2000, approximately 35% of the Partnership's anticipated crude oil
production for the remainder of 2000 had been hedged by crude oil price swap
agreements at an average NYMEX quoted price of $27.00 per bbl, before
transaction and transportation costs. Hedging activities increased Partnership
revenues by approximately $54,000 and decreased Partnership revenues by less
than $1,000 in the three months ended March 31, 1999 and the three months ended
March 31, 2000, respectively, as compared to estimated revenues had no hedging
activities been conducted. At March 31, 2000, the unrealized loss on the
Partnership's existing hedging instruments for future production months in 2000,
approximated $14,000.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2000 and 1999. Oil and gas revenues of
$171,000 for the first quarter of 2000 decreased 49% compared to $334,000 in the
corresponding quarter of 1999 as a result of lower natural gas production
partially offset by higher oil production and higher natural gas and oil prices.
Production of natural gas decreased 78% from 154,000 Mcf in the first quarter of
1999 to 34,000 Mcf in the current quarter due to the sale of properties to
Phillips Petroleum Company ("Phillips") in the second quarter of 1999 and due to
natural depletion. In the second quarter of 1999, the Partnership conveyed its
interests in the West Bryceland and Sailes fields to Phillips ("Phillips
Transaction"). The average price of natural gas increased 40% from $1.98 per Mcf
in the first quarter of 1999 to $2.77 per Mcf in the current quarter. Production
of crude oil in the current quarter totaled 3,000 barrels, with an average sales
price of $26.55 per barrel compared to 2,374 barrels at $11.39 per barrel in the
same quarter last year, representing a volume increase of 26% and a price
increase of 133%.
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Lease operating expenses and severance taxes were $58,000 in the
current quarter versus $133,000 in the first quarter of 1999, a decrease of 56%.
This decrease was primarily due to lower production and lower lifting costs in
the current quarter resulting from the Phillips Transaction. On a unit of
production basis, these expenses increased to $1.13 per Mcfe in the first
quarter of 2000 from $0.79 per Mcfe in the same quarter of 1999, due to the the
decline in production volumes.
General and administrative expenses of $18,000 in the current quarter
decreased 44% from $32,000 in the first quarter of 1999. On a unit of production
basis, these expenses increased 84% to $0.35 per Mcfe compared to $0.19 per Mcfe
in the first quarter of 1999.
In the first quarters of 2000 and 1999, the Partnership incurred
interest expense of $5,000 and $64,000, respectively, on a loan advanced to it
by Kelley Oil in August 1994 ("Initial Loan") to fund part of its drilling
expenditures in excess of contributed capital. The reduction reflects the lower
average note payable balance outstanding in the first quarter of 2000 as
compared to the same period in 1999. See "Liquidity and Capital Resources"
below.
Depreciation, depletion and amortization ("DD&A") expense decreased 67%
from $101,000 in the first quarter of 1999 to $33,000 in the current quarter due
to lower production levels partially offset by higher depletion rates. The
decrease in production was primarily related to the Phillips Transaction. On a
unit of production basis, DD&A expense increased to $0.64 per Mcfe in the first
quarter of 2000 from $0.60 per Mcfe in the same quarter last year.
The Partnership recognized net income of $57,000 or $0.00 per Unit for
the first quarter of 2000. For the first quarter of 1999, the Partnership
recognized net income of $4,000 or $0.00 per Unit. The reasons for the variance
between the first quarter of 2000 and the first quarter of 1999 are described in
the foregoing discussion.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity. Net cash used in the Partnership's operating activities
during the first three months of 2000, as reflected on its statement of cash
flows, totaled $74,000. During the period, funds provided by investing
activities were comprised of net reductions to capital expenditures of $57,000.
During the period, funds provided by financing activities consisted of an
adjustment in the Initial Loan principal of $17,000. As a result of these
activities, the Partnership's cash and cash equivalents remained unchanged from
December 31, 1999.
As part of the Phillips Transaction, the Partnership conveyed its
interest in the West Bryceland and Sailes fields to Phillips for $2.1 million.
In the third quarter of 1999, the sales proceeds were applied to reduce the
Partnership's loan to Kelley Oil.
Capital Resources. The Partnership has completed its development stage.
Accordingly, cash flow from operations should be adequate to meet its expected
capital and general working capital needs.
Distribution Policy. The Partnership maintains a policy of distributing
cash which is not required for the conduct of Partnership business to
Unitholders on a quarterly basis. To meet its financial obligations for drilling
overexpenditures, the Partnership suspended distributions commencing in October
1994 and reinstated a quarterly distribution for only one quarter in 1995. The
Partnership's operating cash flows are currently being applied to pay interest
and principal on the Initial Loan. At March 31, 2000, $183,000 of the $6,000,000
Initial Loan remained outstanding. By continuing to service its debt from
operating cash flow, the Partnership expects to further reduce the outstanding
balance of the Initial Loan.
Year 2000. Contour, on behalf of the Partnership, conducted reviews and
evaluations in response to Year 2000 issues. These issues involved the potential
disruption to systems, processes, and business practices that may have occurred
if system hardware and software utilized by Contour, its vendors, and customers
had been unable to process year 2000 data. Neither Contour nor the Partnership
incurred any disruptions due to year 2000 issues.
The foregoing statements are intended to be and are hereby designated
"Year 2000 Readiness Disclosures" within the meaning of the Year 2000
Information and Readiness Act.
7
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Inflation and Changing Prices. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation.
Accounting Pronouncements. In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
which was amended in June 1999 by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133 - an amendment of FASB Statement No. 133." SFAS No. 133, as
amended, is effective for fiscal years beginning after June 15, 2000, and
establishes accounting and reporting standards for derivative instruments and
hedging activities that require an entity to recognize all derivatives as an
asset or liability measured at its fair value. Depending on the intended use of
the derivative, changes in its fair value will be reported in the period of
change as either a component of earnings or a component of other comprehensive
income. Retroactive application to periods prior to adoption is not allowed. The
Partnership has not quantified the impact of adoption on its financial
statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
See discussion in Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Hedging Activities.
FORWARD-LOOKING STATEMENTS
Statements contained in this Report and other materials filed or to be
filed by the Partnership with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Partnership or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the Partnership. Actual performance, prospects, developments and
results may differ materially from any or all anticipated results due to
economic conditions and other risks, uncertainties and circumstances partly or
totally outside the control of the Partnership, including rates of inflation,
oil and natural gas prices, uncertainty of reserve estimates, rates and timing
of future production of oil and natural gas, exploratory and development
activities, acquisition risks, changes in the level and timing of future costs
and expenses related to drilling and operating activities and those risk factors
described on pages 9 and 10 of the Partnership's Annual Report on Form 10-K for
the fiscal year ended December 31, 1999.
Words such as "anticipated," "expect," "estimate," "project" and
similar expressions are intended to identify forward-looking statements.
Forward-looking statements include the risk factors described in the
Partnership's Form 10-K mentioned above.
8
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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
EXHIBIT
NUMBER: EXHIBIT
27 Financial Data Schedule (included only in the
electronic filing of this document).
(b) Reports on Form 8-K:
No reports on Form 8-K were filed by the Registrant during the first quarter of
2000.
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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.
KELLEY PARTNERS 1992
DEVELOPMENT DRILLING PROGRAM
By: KELLEY OIL CORPORATION
Managing General Partner
Date: May15, 2000 By: /s/ Rick G. Lester
-------------------------------
Rick G. Lester
Senior Vice President and
Chief Financial Officer
(Duly Authorized Officer)
(Principal Financial Officer)
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INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: EXHIBIT
------- -------
<S> <C>
27 Financial Data Schedule (included only in the
electronic filing of this document).
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<CASH> 0
<SECURITIES> 0
<RECEIVABLES> 225
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 225
<PP&E> 41,409
<DEPRECIATION> 40,429
<TOTAL-ASSETS> 1,205
<CURRENT-LIABILITIES> 78
<BONDS> 183
0
0
<COMMON> 0
<OTHER-SE> 944
<TOTAL-LIABILITY-AND-EQUITY> 1,205
<SALES> 171
<TOTAL-REVENUES> 171
<CGS> 0
<TOTAL-COSTS> 58
<OTHER-EXPENSES> 51
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5
<INCOME-PRETAX> 57
<INCOME-TAX> 0
<INCOME-CONTINUING> 57
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 57
<EPS-BASIC> .00
<EPS-DILUTED> .00
</TABLE>
