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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 SEPTEMBER 30, 2000 COMMISSION FILE NO. 0-23784
KELLEY PARTNERS 1994 DEVELOPMENT
DRILLING PROGRAM
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0419001
(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 1994 DEVELOPMENT DRILLING PROGRAM
INDEX
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION PAGE
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<S> <C>
Item I. Financial Statements:
Balance Sheets as of December 31, 1999 and September 30, 2000 (unaudited) ......................... 2
Statements of Income for the three months and nine months ended
September 30, 1999 and 2000 (unaudited)......................................................... 3
Statements of Cash Flows for the nine months ended September 30, 1999 and 2000 (unaudited)......... 4
Notes to Financial Statements (unaudited).......................................................... 5
Item II. Management's Discussion and Analysis of Financial Condition and Results of Operations.... 6
Item III. Quantitative and Qualitative Disclosure About Market Risk................................ 9
PART II. OTHER INFORMATION.............................................................................. 10
</TABLE>
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31, SEPT. 30,
1999 2000
------------ ---------
(UNAUDITED)
<S> <C> <C>
ASSETS:
Cash and cash equivalents ................................... $ -- $ --
Accounts receivable - trade ................................. 16 2
Accounts receivable - affiliates ............................ 905 979
-------- --------
Total current assets ........................................ 921 981
-------- --------
Oil and gas properties, successful efforts method:
Properties subject to amortization ........................ 32,619 32,540
Less: Accumulated depreciation, depletion and
amortization ........................................... (27,132) (27,667)
-------- --------
Total oil and gas properties ................................ 5,487 4,873
-------- --------
Total assets ................................................... $ 6,408 $ 5,854
======== ========
LIABILITIES:
Accounts payable and accrued expenses ....................... $ 121 $ 78
-------- --------
Total current liabilities ................................... 121 78
-------- --------
Total liabilities .............................................. 121 78
-------- --------
PARTNERS' EQUITY:
LP Unitholders' equity ...................................... 346 327
GP Unitholders' equity ...................................... 5,693 5,221
Managing and Special General Partners' equity ............... 248 228
-------- --------
Total partners' equity ......................................... 6,287 5,776
-------- --------
Total liabilities and partners' equity ......................... $ 6,408 $ 5,854
======== ========
</TABLE>
See Notes to Financial Statements.
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KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPT. 30, NINE MONTHS ENDED SEPT. 30,
---------------------------- ---------------------------
1999 2000 1999 2000
------- ------- ------- -------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales ......................... $ 727 $ 630 $ 2,828 $ 1,903
Gain on sale of properties ................ -- -- 2,012 --
------- ------- ------- -------
Total revenues ............................ 727 630 4,840 1,903
------- ------- ------- -------
EXPENSES:
Lease operating expenses .................. 110 93 443 284
Severance taxes ........................... 58 21 166 58
Exploration expenses ...................... -- -- -- --
General and administrative expenses ....... 129 71 340 235
Depreciation, depletion and amortization .. 289 167 914 535
------- ------- ------- -------
Total expenses ............................ 586 352 1,863 1,112
------- ------- ------- -------
Net income ................................... $ 141 $ 278 $ 2,977 $ 791
======= ======= ======= =======
Net income allocable to LP and GP unitholders $ 135 $ 267 $ 2,859 $ 760
======= ======= ======= =======
Net income allocable to Managing and
Special General Partners .................. $ 6 $ 11 $ 118 $ 31
======= ======= ======= =======
Net income per LP and GP unit ................ $ .01 $ .01 $ .14 $ .04
======= ======= ======= =======
Average LP and GP units outstanding .......... 20,864 20,864 20,864 20,864
======= ======= ======= =======
</TABLE>
See Notes to Financial Statements.
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KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPT. 30,
---------------------------
1999 2000
-------- --------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income ................................................... $ 2,977 $ 791
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sale of properties ................................. (2,012) --
Depreciation, depletion and amortization ................... 914 535
Exploration expenses ....................................... -- --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable ................. 2,180 (60)
Increase (decrease) in accounts payable and accrued
expenses ................................................. 3 (43)
-------- --------
Net cash provided by operating activities .................... 4,062 1,223
-------- --------
INVESTING ACTIVITIES:
Capital expenditures ......................................... (169) 79
Proceeds from sale of properties ............................. 8,326 --
-------- --------
Net cash provided by investing activities .................... 8,157 79
-------- --------
FINANCING ACTIVITIES:
Distributions to partners .................................... (12,219) (1,302)
-------- --------
Net cash used in financing activities ........................ (12,219) (1,302)
-------- --------
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.
4
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KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - BASIS OF PRESENTATION
General. The accompanying unaudited interim financial statements of
Kelley Partners 1994 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 in all material respects of the results for the interim periods
presented. The results of operations for the three and nine months ended
September 30, 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.
Changes in Presentation. Certain 1999 financial statement items have
been reclassified to conform to the 2000 presentation.
NOTE 2 - NEW ACCOUNTING PRONOUNCEMENTS
The Partnership plans to adopt Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended,
requires that all derivatives be recognized as either assets or liabilities and
measured at fair value, and changes in the fair value of derivatives be
reported in current earnings, unless the derivative is designated and effective
as a hedge. If the intended use of the derivative is to hedge the exposure to
changes in the fair value of an asset, a liability or firm commitment, then the
changes in the fair value of the derivative instrument will generally be offset
in the income statement by the change in the item's fair value. However, if the
intended use of the derivative is to hedge the exposure to variability in
expected future cash flows then the changes in fair value of the derivative
instrument will generally be reported in Other Comprehensive Income (OCI). The
gains and losses on the derivative instrument that are reported in OCI will be
reclassified to earnings in the period in which earnings are impacted by the
hedged item.
Contour Energy Co. ("Contour") periodically uses forward sales
contracts, swap agreements, natural gas basis swap agreements, collars and
options to reduce exposure to downward price fluctuations on its natural gas
and crude oil production. Contour's hedging activities also cover the
production attributable to the interest of the public unitholders in this
partnership. Contour has received a mark-to-market valuation report from its
counterparty dated November 7, 2000. Based on this report, when SFAS 133 is
adopted on January 1, 2001, a liability of approximately $190,000 would be
recorded by the partnership to reflect the fair market value of hedges
currently in place for the periods subsequent to January 1, 2001. Because the
derivatives currently in place qualify for hedge accounting, an offsetting
entry would be made to OCI. Due to commodity price volatility, the fair value
of Contour's derivative instruments has changed dramatically since September
30, 2000 (See "Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Hedging Activities"). Volatility in the
commodity price markets prevents management of the partnership from determining
the actual transitional valuation effect on future results of operations or
financial position once SFAS 133 is implemented on January 1, 2001.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
In 1994, Kelley Partners 1994 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 91.85% of the
Units, together with its 3.94% managing general partnership interest.
RECENT DEVELOPMENTS
Drilling Operations. Since inception, the Partnership participated in
drilling 92 gross (29.31 net) wells, of which 88 gross (26.64 net) wells were
found productive and 4 gross (2.67 net) wells were dry.
Hedging Activities. Contour periodically uses forward sales contracts,
natural gas and crude oil price swap agreements, collars and options to reduce
exposure to downward price fluctuations on its natural gas and crude oil
production. Contour's hedging activities also cover the oil and gas production
attributable to the interest of the public unitholders in its subsidiary
partnerships. Contour does not engage in speculative transactions. During 2000,
Contour has used price swap agreements and collars. Price swap agreements
generally provide for Contour to receive or make counterparty payments on the
differential between a fixed price and a variable indexed price for natural gas
and crude oil. Collars combine put and call options to establish a ceiling and
a floor. Contour normally employs the average NYMEX price for the last three
days of the contract for natural gas and the monthly average of closing NYMEX
prices for crude oil as the underlying index ("Index Price"). To the extent the
Index Price closes above the established ceiling Contour must make payments to
the counterparty on the differential between the Index Price and the ceiling.
Conversely, if the Index price closes below the established floor, the
counterparty must make payments to Contour on the differential between the
Index Price and the floor. If the Index Price closes between the ceiling and
the floor, no settlement is due. Gains and losses realized by the Partnership
from hedging activities are included in oil and gas revenues and average sales
prices in the period that the related production is sold. However, see Note 2 -
New Accounting Pronouncements.
Through natural gas price swap agreements and collars, approximately
54%, 94%, 44% and 65% of the Partnership's natural gas production was hedged for
the third quarter of 1999, the third quarter of 2000, the first nine months of
1999 and the first nine months of 2000, respectively. As of September 30, 2000,
approximately 50,000 Mmbtus of the Partnership's natural gas production for
October 2000 has been hedged by natural gas price swap agreements at an average
Index Price of $2.60 per Mmbtu before transaction and transportation costs. As
of September 30, 2000, approximately 150,000 Mmbtus of the Partnership's natural
gas production for October through December 2000 has been hedged by collars at a
floor of $4.00 per Mmbtu and a ceiling of $4.98 per Mmbtu. As of the date of
this report, Contour has three collars in place for 15,000 Mmbtus per day each
totaling 45,000 Mmbtus per day of expected natural gas production for the
calendar year 2001. Approximately 1,400 Mmbtus per day of these volumes relate
to the Partnership's production. The terms of the first collar include a ceiling
of $5.00/Mmbtu and a floor of $3.55/Mmbtu at a closing Index Price above
$3.00/Mmbtu. However, at prices below $3.00/Mmbtu, the floor moves to an Index
Price plus $0.55/Mmbtu. The terms of the second collar include a ceiling of
$5.00/Mmbtu and a floor of $3.75/Mmbtu at a closing Index Price above
$3.09/Mmbtu. However, at prices below $3.09/Mmbtu, the floor moves to an Index
Price plus $0.66/Mmbtu. The terms of the third collar include a ceiling of
$5.33/Mmbtu and a floor of $4.00/Mmbtu at the closing Index Price.
Through crude oil price swap agreements and collars, approximately 46%,
48%, 17% and 62% of the Partnership's crude oil production was hedged for the
third quarter of 1999, the third quarter of 2000, the first nine months of 1999
and the first nine months of 2000, respectively. As of September 30, 2000,
Contour has two collars in place covering an average of 900 barrels per day of
expected crude oil production for the remainder of 2000 and an average of 598
barrels per day of expected crude oil production for calendar year 2001.
Approximately, 2 and 1 barrel(s) per day of these volumes related to the
Partnership's production for the remainder of 2000 and 2001, respectively.
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The terms of the first collar include a ceiling of $32.00/bbl and a floor of
$25.24/bbl at a closing Index Price above $22.00/bbl. However, at prices below
$22.00/bbl, the floor moves to an Index Price plus $3.24 /bbl. The terms of the
second collar include a ceiling of $32.48/bbl and a floor of $27.20/bbl at a
closing Index Price above $23.00/bbl. However, at prices below $23.00/bbl, the
floor moves to an Index Price plus $4.20/bbl.
Included within oil and gas revenues for the three months and nine
months ended September 30, 1999 and 2000 was approximately $(136,000),
$(223,000), $142,000 and $(313,000), respectively, representing net (losses)
and net gains from hedging activities. At September, 30, 2000, the
mark-to-market unrealized loss on Contour's existing hedging instruments for
future production months approximated $6.7 million, of which $2.7 million
related to October 2000. As to the aforementioned losses, approximately
$300,000 and $120,000, respectively, related to the Partnership's production.
Contour, under the terms of its existing hedge instruments, is required, from
time to time, to provide collateral to the counterparty(s). The amount of
collateral required is a function of the mark to market value of the hedge
instruments at a point in time as determined by the counterparty(s). 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.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2000 and 1999. Oil and gas revenues
of $630,000 for the third quarter of 2000 decreased 13% compared to $727,000 in
the corresponding quarter of 1999 primarily as a result of lower gas
production, partially offset by higher oil and natural gas prices. Production
of natural gas decreased 47% from 387,000 Mcf in the third quarter of 1999 to
206,000 Mcf in the same period of 2000, primarily due to normal production
decline.
Lease operating expenses and severance taxes were $114,000 in the
current quarter versus $168,000 in the third quarter of 1999. This 32% decrease
was primarily from lower severance taxes due to lower production volumes. On a
unit of production basis, these expenses increased from $0.42 per Mcfe in the
third quarter of 1999 to $0.55 per Mcfe in the same quarter of 2000, primarily
as a result of lower production levels in the third quarter 2000.
General and administrative ("G&A") expenses of $71,000 in the current
quarter decreased 45% from $129,000 in the third quarter of 1999, reflecting
the Partnership's share of administration costs associated with operations of
Contour. On a unit of production basis, G&A expenses increased from $0.32 per
Mcfe in the third quarter of 1999 to $0.34 per Mcfe in the current quarter.
Depreciation, depletion and amortization ("DD&A") expenses decreased
42% from $289,000 in the third quarter of 1999 to $167,000 in the current
quarter, primarily as a result of decreased production levels. The
units-of-production DD&A rate for oil & gas activities was $0.71 per Mcfe in
the third quarter of 1999 compared to $0.80 per Mcfe in the third quarter of
2000.
The Partnership recognized net income of $278,000, or $0.01 per Unit,
for the third quarter of 2000 compared to third quarter 1999 net income of
$141,000, or $0.01 per Unit. The reasons for the variance between the third
quarter of 2000 and the third quarter of 1999 are described in the foregoing
discussion.
Nine Months Ended September 30, 2000 and 1999. Oil and gas revenues of
$1,903,000 for the first nine months of 2000 decreased 33% compared to
$2,828,000 in the corresponding period of 1999 primarily as a result of lower
natural gas production, partially offset by higher prices. Production of
natural gas decreased 54% from 1,500,000 Mcf in the first nine months of 1999
to 685,000 Mcf in the current period primarily due to the May 1999 sale of
properties to Phillips Petroleum Company ("Phillips"). Natural gas prices
increased 49% to $2.82 per Mcf in the current period from $1.89 per Mcf in the
first nine months of 1999. In the second quarter of 1999, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips. This
transaction resulted in a second quarter 1999 gain on sale of properties of
$2,012,000.
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Lease operating expenses and severance taxes were $342,000 in the
first nine months of 2000 versus $609,000 in the first nine months of 1999.
This 44% decrease was primarily due to the sale of properties to Phillips in
the first half of 1999. On a unit of production basis, these expenses increased
to $0.50 per Mcfe in the current period from $0.39 per Mcfe in the same period
of 1999, primarily as a result of lower production levels in the first nine
months of 2000.
G&A expenses of $235,000 in the current period decreased 31% from
$340,000 in the first nine months of 1999, reflecting the Partnership's share
of administration costs associated with operations of Contour. On a unit of
production basis, these expenses increased from $0.22 per Mcfe in the first
nine months of 1999 to $0.34 per Mcfe in the current period.
DD&A expense decreased 41% from $914,000 in the first nine months of
1999 to $535,000 in the current period, primarily as a result of decreased
current period production related to the sale of properties in the first half
of 1999 to Phillips. The units-of-production DD&A rate for oil & gas activities
was $0.59 per Mcfe in the first nine months of 1999 compared to $0.78 per Mcfe
in the same period in of 2000.
The Partnership recognized net income of $791,000, or $.04 per Unit,
for the first nine months of 2000 compared to net income of $2,977,000, or
$0.14 per Unit, for the first nine months of 1999. The reasons for the variance
between the first nine months of 2000 and the first nine months of 1999 are
described in the foregoing discussion.
The results of operations for the three and nine months ended
September 30, 2000 are not necessarily indicative of the Partnership's
operating results to be expected for the full year.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity. Net cash provided by the Partnership's operating activities
during the first nine months of 2000, as reflected on its statement of cash
flows, totaled $1,223,000. During the period, funds provided by investing
activities were comprised of net reductions to capital expenditures of $79,000.
For the first nine months of 2000, funds used in financing activities consisted
of cash distributions to partners of $1,302,000. As a result of these
activities, the Partnership's cash and cash equivalents remained unchanged from
December 31, 1999.
Capital Resources. The capitalization of the Partnership was completed
in 1997. Cash flows from operations are expected to be adequate to meet the
Partnership's capital expenditures and 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. In March, May and August 2000,
the Partnership made quarterly distributions of $0.02 per Unit (aggregating
$1,302,000), compared to distributions of $0.05, $0.09 and $0.42 (including
$0.38 per unit related to the proceeds from the sale of properties to Phillips)
per Unit in March, May and August 1999, respectively (aggregating $12,219,000).
The Partnership intends to continue making quarterly distributions consistent
with its cash distribution policy.
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. The Partnership plans to adopt Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement,
as amended, requires that all derivatives be recognized as either assets or
liabilities and measured at fair value, and changes in the fair value of
derivatives be reported in current earnings, unless the derivative is
designated and effective as a hedge. If the intended use of the derivative is
to hedge the exposure to changes in the fair value of an asset, a liability or
firm commitment, then the changes in the fair value of the derivative
instrument will generally be offset in the income statement by the change in
the item's fair value. However, if the intended use of the derivative is to
hedge the exposure to variability in expected future cash flows then the
changes in fair value of the derivative instrument will generally be reported
in Other Comprehensive Income (OCI). The gains and losses on the derivative
instrument that are reported in OCI will be reclassified to earnings in the
period in which earnings are impacted by the hedged item.
8
<PAGE> 10
Contour periodically uses forward sales contracts, swap agreements,
natural gas basis swap agreements, collars and options to reduce exposure to
downward price fluctuations on its natural gas and crude oil production.
Contour's hedging activities also cover the production attributable to the
interest of the public unitholders in this partnership. Contour has received a
mark-to-market valuation report from its counterparty dated November 7, 2000.
Based on this report, when SFAS 133 is adopted on January 1, 2001, a liability
of approximately $190,000 would be recorded by the partnership to reflect the
fair market value of hedges currently in place for the periods subsequent to
January 1, 2001. Because the derivatives currently in place qualify for hedge
accounting, an offsetting entry would be made to OCI. Due to commodity price
volatility, the fair value of Contour's derivative instruments has changed
dramatically since September 30, 2000 (See "Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Hedging
Activities"). Volatility in the commodity price markets prevents management of
the partnership from determining the actual transitional valuation effect on
future results of operations or financial position once SFAS 133 is implemented
on January 1, 2001.
ITEM 3. 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,
natural gas prices, uncertainty of reserve estimates, rates and timing of future
production of oil and 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.
9
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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
third quarter of 2000.
10
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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 1994
DEVELOPMENT DRILLING PROGRAM
By: KELLY OIL CORPORATION
Managing General Partner
Date: November 14, 2000 By: /s/ Rick G. Lester
-------------------------------
Rick G. Lester
Chief Financial Officer
(Duly Authorized Officer)
(Principal Accounting Officer)
<PAGE> 13
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
27 Financial Data Schedule (included only in the
electronic filing of this document).
</TABLE>
