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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, 1999 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
----
<S> <C>
Item I. Financial Statements:
Balance Sheets as of December 31, 1998 and September 30, 1999 (unaudited) ........................ 2
Statements of Income for the three months and nine months ended
September 30, 1998 and 1999 (unaudited)........................................................ 3
Statements of Cash Flows for the nine months ended September 30, 1998 and 1999 (unaudited)........ 4
Notes to Financial Statements (unaudited)......................................................... 5
Item II. Management's Discussion and Analysis of Financial Condition and Results of Operations... 7
Item III. Quantitative and Qualitative Disclosure About Market Risk............................... 10
PART II. OTHER INFORMATION................................................................................. 11
</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,
1998 1999
------------ ---------
(UNAUDITED)
<S> <C> <C>
ASSETS:
Cash and cash equivalents .............................................. $ -- $ --
Accounts receivable - trade ............................................ 20 23
Accounts receivable - affiliates ....................................... 3,076 893
-------- --------
Total current assets ................................................... 3,096 916
-------- --------
Oil and gas properties, successful efforts method:
Properties subject to amortization ................................... 45,294 32,528
Less: Accumulated depreciation, depletion and amortization .......... (32,627) (26,921)
-------- --------
Total oil and gas properties ........................................... 12,667 5,607
-------- --------
Total assets .............................................................. $ 15,763 $ 6,523
======== ========
LIABILITIES:
Accounts payable and accrued expenses .................................. $ 173 $ 176
-------- --------
Total current liabilities .............................................. 173 176
-------- --------
Total liabilities ......................................................... 173 176
-------- --------
PARTNERS' EQUITY:
LP Unitholders' equity ................................................. 857 349
GP Unitholders' equity ................................................. 14,116 5,747
Managing and Special General Partners' equity .......................... 617 251
-------- --------
Total partners' equity .................................................... 15,590 6,347
-------- --------
Total liabilities and partners' equity .................................... $ 15,763 $ 6,523
======== ========
</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,
---------------------------- ---------------------------
1998 1999 1998 1999
----------- ------------ --------- -------------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales .................................. $ 1,897 $ 727 $ 6,709 $ 2,828
Gain on sale of properties ......................... -- -- -- 2,012
------- ------- ------- -------
Total revenues ..................................... 1,897 727 6,709 4,840
------- ------- ------- -------
EXPENSES:
Lease operating expenses ........................... 413 110 900 443
Severance taxes .................................... 97 58 349 166
Exploration expenses ............................... -- -- -- --
General and administrative expenses ................ 227 129 676 340
Depreciation, depletion and amortization ........... 664 289 2,242 914
------- ------- ------- -------
Total expenses ..................................... 1,401 586 4,167 1,863
------- ------- ------- -------
Net income ............................................ $ 496 $ 141 $ 2,542 $ 2,977
======= ======= ======= =======
Net income allocable to LP and GP unitholders ......... $ 476 $ 135 $ 2,441 $ 2,859
======= ======= ======= =======
Net income allocable to Managing and
Special General Partners ........................... $ 20 $ 6 $ 101 $ 118
======= ======= ======= =======
Net income per LP and GP unit ......................... $ .02 $ .01 $ .12 $ .14
======= ======= ======= =======
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,
---------------------------
1998 1999
---------- -----------
<S> <C> <C>
OPERATING ACTIVITIES:
Net income ............................................................. $ 2,542 $ 2,977
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sale of properties ........................................... -- (2,012)
Depreciation, depletion and amortization ............................. 2,242 914
Exploration expenses ................................................. -- --
Changes in operating assets and liabilities:
Decrease in accounts receivable ...................................... 2,287 2,180
(Decrease) increase in accounts payable and accrued expenses ........ (230) 3
-------- --------
Net cash provided by operating activities .............................. 6,841 4,062
-------- --------
INVESTING ACTIVITIES:
Capital expenditures ................................................... -- (169)
Proceeds from sale of properties ....................................... (107) 8,326
-------- --------
Net cash (used in) provided by investing activities .................... (107) 8,157
-------- --------
FINANCING ACTIVITIES:
Distributions to partners .............................................. (6,734) (12,219)
-------- --------
Net cash used in financing activities .................................. (6,734) (12,219)
-------- --------
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.
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KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - GENERAL, INDUSTRY CONDITIONS AND LIQUIDITY
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 of the results for the interim periods presented. The results of
operations for the period ended September 30, 1999 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, 1998.
These unaudited interim financial statements should be read in conjunction with
the audited financial statements and notes thereto included in the Partnership's
1998 Annual Report on Form 10-K.
During 1998 and through the first quarter of 1999, the oil and gas
industry experienced a world-wide excess of supply over demand for oil and
natural gas resulting in sharply reduced prices. As a result, many entities in
the oil and gas industry, including Kelley Oil Corporation, managing general
partner of the Partnership ("Kelley Oil") and a wholly owned subsidiary of
Contour Energy Co. (formerly Kelley Oil & Gas Corporation) ("Contour") and the
Partnership, experienced reduced profitability and cash flows which, in turn,
created significant liquidity problems. To address these liquidity issues,
Contour has taken the measures discussed in the following paragraphs.
In April 1999, Contour entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
its interests in the Bryceland, West Bryceland and Sailes fields in north
Louisiana. Pursuant to the agreement, Contour: (1) received an $83 million cash
payment (subject to certain post-closing adjustments), (2) retained a 42 Bcf,
8-year volumetric overriding royalty interest and a 1% override on the excess
production above such royalty interest and (3) retained 25% of its working
interest in the Cotton Valley formation. In addition, Phillips, will at its risk
and expense, operate, develop, exploit and explore the properties thereby
relieving Contour of significant operating, exploration and development costs in
the future. The transaction closed on May 17, 1999.
As part of the Phillips transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$8.3 million, pending adjustments. The Partnership's reserve quantities
attributable to such fields represent approximately one-half of the
Partnership's total reserve quantities at January 1, 1999 and one-half of its
total 1998 production. The sales proceeds were distributed to the Partnership in
the third quarter of 1999.
In April 1999, Contour negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of Contour's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by Contour. On June 2, 1999, Contour offered to repurchase $35
million principal amount of the Notes at a repurchase price equal to 104% of the
principal amount, plus accrued and unpaid interest to the date of the
repurchase, in accordance with the Notes indenture. On June 30, 1999, Contour
funded $37.5 million for the repurchase (including $1.1 million for accrued
interest and commitment fee and $1.4 million premium).
In April 1999, Contour began an offer to purchase ("Offer to Purchase")
the outstanding principal amounts of its 7 7/8% Convertible Subordinated Notes
due December 15, 1999 and its 8 1/2% Convertible Subordinated Debentures due
April 1, 2000 (collectively, the "Securities") at a price equal to $590 per
$1,000 principal amount. On May 17, 1999, Contour funded the repurchase of $46.1
million of the Securities through the Offer to Purchase at a cost of
approximately $28.5 million (not including accrued interest paid of $1.2
million).
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The net proceeds from the combination of these transactions and cash on
hand were used by Contour to repay all borrowings outstanding under its credit
facility of $115.5 million plus accrued interest, to fund cash collateral for a
$1.5 million letter of credit which was subsequently increased to $7.5 million,
to fund the repurchase of $46.1 million aggregate principal amount of Contour's
7 7/8% convertible Subordinated Notes due December 15, 1999 and 8 1/2%
Convertible Subordinated Debentures due April 1, 2000, at a cost of
approximately $28.5 million, all at May 17, 1999 and to repurchase $35 million
of Notes at 104% of their principal amount. Contour will use any remaining net
proceeds for general corporate purposes.
While industry conditions cannot be predicted with certainty and are
dependent upon a number of commodity and economic factors which are beyond
Contour's control, Contour believes that the cash on hand subsequent to the
consummation of the above transactions and the recent increase in oil and
natural gas prices, if continued, will sustain its operations over the
short-term. However, Contour will continue to have significant debt outstanding
and limited ability to incur further indebtedness, which, combined with industry
conditions beyond its control, may adversely affect its financial condition,
results of operations and cash flows.
Changes in Presentation. Certain 1998 financial statement items have
been reclassified to conform to the 1999 presentation.
Comprehensive Income. In June 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("SFAS 130"). SFAS 130 is effective for periods beginning
after December 15, 1997. SFAS 130 establishes standards for reporting and
displaying comprehensive income and its components. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
As of September 30, 1999, there are no adjustments ("Other comprehensive
income") to net income in deriving comprehensive income.
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").
SFAS 133 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.
SFAS 133 is effective for all fiscal quarters of fiscal years beginning
after June 15, 2000. Earlier application of SFAS 133 is encouraged, but
retroactive application to periods prior to adoption is not allowed. The
Partnership is currently evaluating the impact of SFAS 133.
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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. (formerly Kelley Oil & Gas
Corporation) ("Contour"), owns 91.85% of the Units, together with its 3.94%
managing general partnership interest.
In April 1999, the Partnership conveyed its interest in the West
Bryceland and Sailes fields to Phillips Petroleum Company for $8.3 million,
pending adjustments. The Partnership's reserve quantities attributable to such
fields represent approximately one-half of the Partnership's total reserve
quantities at January 1, 1999 and one-half of its total 1998 production. The
sales proceeds were distributed to the Partnership in the third quarter of 1999.
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. See "Liquidity and
Capital Resources" below.
Hedging Activities. Contour periodically uses forward sales contracts,
natural gas and crude oil price 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 and crude oil
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 54% and 44% of
the Partnership's natural gas production for the third quarter of 1999 and first
nine months of 1999, respectively, was affected by hedging transactions at an
average NYMEX quoted price of $2.09 per Mmbtu and $2.18 per Mmbtu, respectively,
before transaction and transportation costs. Through crude oil price swap
agreements, the Partnership hedged approximately 46% and 17% of its crude oil
production for the third quarter of 1999 and the first nine months of 1999,
respectively, at average NYMEX quoted prices of $20.00 per bbl, before
transaction and transportation costs. Hedging activities decreased Partnership
revenues by approximately $136,000 in the third quarter of 1999 and increased
Partnership revenues by approximately $142,000 in the first nine months of 1999
as compared to estimated revenues had no hedging activities been conducted. As
of September 30, 1999, approximately 22% of the Partnership's anticipated
natural gas production for the remainder of 1999 had been hedged by natural gas
price swap agreements at an average NYMEX quoted price of $2.13 per Mmbtu before
transaction and transportation costs. As of September 30, 1999, approximately
56% of the Partnership's anticipated crude oil production for the remainder of
1999 had been hedged by crude oil price swap agreements at an average NYMEX
quoted price of $20.00 per bbl., before transaction and transportation costs.
RESULTS OF OPERATIONS
Three Months Ended September 30, 1999 and 1998. Oil and gas revenues of
$727,000 for the third quarter of 1999 decreased 62% compared to $1,897,000 in
the corresponding quarter of 1998 primarily as a result of lower gas production.
Production of natural gas decreased 60% from 959,000 Mcf in the third quarter of
1998 to 387,000 Mcf in the same period of 1999. Gas production decreased due to
the sale of properties to Phillips Petroleum Company, see Liquidity and Capital
Resources for further discussion and natural depletion.
Lease operating expenses and severance taxes were $168,000 in the
current quarter versus $510,000 in the third quarter of 1998. This 67% decrease
was primarily due to the sale of properties in the second quarter of 1999. On a
unit of
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production basis, these expenses increased from $0.52 per Mcfe in the third
quarter of 1998 to $0.42 per Mcfe in the same quarter of 1999.
General and administrative ("G&A") expenses of $129,000 in the current
quarter decreased 43% from $227,000 in the third quarter of 1998, reflecting the
Partnership's share of administration costs associated with operations of
Contour. On a unit of production basis, G&A expenses increased from $0.23 per
Mcfe in the third quarter of 1998 to $0.32 per Mcfe in the current quarter.
Depreciation, depletion and amortization ("DD&A") expenses decreased
56% from $664,000 in the third quarter of 1998 to $289,000 in the current
quarter, primarily as a result of decreased production related to the sale of
properties in the second quarter of 1999.
The Partnership recognized net income of $141,000 or $0.01 per Unit for
the third quarter of 1999 compared to third quarter 1998 net income of $496,000
or $0.02 per Unit. The reasons for the variance between the third quarter of
1999 and the third quarter of 1998 are described in the foregoing discussion.
Nine Months Ended September 30, 1999 and 1998. Oil and gas revenues of
$2,828,000 for the first nine months of 1999 decreased 58% compared to
$6,709,000 in the corresponding period of 1998 primarily as a result of lower
gas production and prices. Production of natural gas decreased 54% from
3,234,000 Mcf in the first nine months of 1998 to 1,500,000 Mcf in the current
period primarily due to the sale of properties to Phillips Petroleum Company.
Natural gas prices decreased 5% to $1.89 per Mcf in the current period from
$1.99 per Mcf in the first nine months of 1998. In the second quarter of 1999,
the Partnership conveyed its interest in the West Bryceland and Sailes fields to
Phillips Petroleum Company. This transaction resulted in a second quarter 1999
gain on sale of properties of $2,012,000, see Liquidity and Capital Resources
for further discussion.
Lease operating expenses and severance taxes were $609,000 in the first
nine months of 1999 versus $1,249,000 in the first nine months of 1998. This 51%
decrease was primarily due to the sale of properties in the first half of 1999.
On a unit of production basis, these expenses increased to $0.39 per Mcfe in the
current period from $0.37 per Mcfe in the same period of 1998.
G&A expenses of $340,000 in the current period decreased 50% from
$676,000 in the first nine months of 1998, reflecting the Partnership's share of
administration costs associated with operations of Contour. On a unit of
production basis, these expenses increased from $0.20 per Mcfe in the first nine
months of 1998 to $0.22 per Mcfe in the current period.
DD&A expense decreased 59% from $2,242,000 in the first nine months of
1998 to $914,000 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.
The Partnership recognized net income of $2,977,000 or $0.14 per Unit
for the first nine months of 1999 compared to net income of $2,542,000 or $0.12
per Unit for the first nine months of 1998. The reasons for the variance between
the first nine months of 1999 and the first nine months of 1998 are described in
the foregoing discussion.
The results of operations for the quarter and nine months ended
September 30, 1999 are not necessarily indicative of the Partnership's operating
results to be expected for the full year.
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LIQUIDITY AND CAPITAL RESOURCES
Liquidity. Net cash provided by the Partnership's operating activities
during the first nine months of 1999, as reflected on its statement of cash
flows, totaled $4,062,000. During the period, funds provided by investing
activities included proceeds from the sale of properties to Phillips of
$8,326,000 partially offset by capital expenditures of $169,000. For the first
nine months of 1999, funds used in financing activities consisted of cash
distributions to partners of $12,219,000. As a result of these activities, the
Partnership's cash and cash equivalents remained unchanged from December 31,
1998.
During 1998 and through the first quarter of 1999, the oil and gas
industry experienced a world-wide excess of supply over demand for oil and
natural gas resulting in sharply reduced prices. As a result, many entities in
the oil and gas industry, including Kelley Oil Corporation and the Partnership,
experienced reduced profitability and cash flows which, in turn, created
significant liquidity problems. To address these liquidity issues, Contour has
taken the measures discussed in the following paragraphs.
In April 1999, Contour entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
its interests in the Bryceland, West Bryceland and Sailes fields in north
Louisiana. Pursuant to the agreement, Contour: (1) received an $83 million cash
payment (subject to certain post-closing adjustments), (2) retained a 42 Bcf,
8-year volumetric overriding royalty interest and a 1% override on the excess
production above such royalty interest and (3) retained 25% of its working
interest in the Cotton Valley formation. In addition, Phillips, will at its risk
and expense, operate, develop, exploit and explore the properties thereby
relieving Contour of significant operating, exploration and development costs in
the future. The transaction closed on May 17, 1999.
As part of the Phillips transaction described above, the Partnership
conveyed its interest in the West Bryceland and Sailes fields to Phillips for
$8.3 million, pending adjustments. The Partnership's reserve quantities
attributable to such fields represent approximately one-half of the
Partnership's total reserve quantities at January 1, 1999 and one-half of its
total 1998 production. The sales proceeds were distributed to the Partnership in
the third quarter of 1999.
In April 1999, Contour negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of Contour's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by Contour. On June 2, 1999, Contour offered to repurchase $35
million principal amount of the Notes at a repurchase price equal to 104% of the
principal amount, plus accrued and unpaid interest to the date of the
repurchase, in accordance with the Notes indenture. On June 30, 1999, Contour
funded $37.5 million for the repurchase (including $1.1 million for accrued
interest and commitment fee and $1.4 million premium).
In April 1999, Contour began an offer to purchase ("Offer to Purchase")
the outstanding principal amounts of its 7 7/8% Convertible Subordinated Notes
due December 15, 1999 and its 8 1/2% Convertible Subordinated Debentures due
April 1, 2000 (collectively, the "Securities") at a price equal to $590 per
$1,000 principal amount. On May 17, 1999, Contour funded the repurchase of $46.1
million of the Securities through the Offer to Purchase at a cost of
approximately $28.5 million (not including accrued interest paid of $1.2
million).
The net proceeds from the combination of these transactions and cash on
hand were used by Contour to repay all borrowings outstanding under its credit
facility of $115.5 million plus accrued interest, to fund cash collateral for a
$1.5 million letter of credit which was subsequently increased to $7.5 million,
to fund the repurchase of $46.1 million aggregate principal amount of Contour's
7 7/8% convertible Subordinated Notes due December 15, 1999 and 8 1/2%
Convertible Subordinated Debentures due April 1, 2000, at a cost of
approximately $28.5 million, all at May 17, 1999 and to repurchase $35 million
of Notes at 104% of their principal amount. Contour will use any remaining net
proceeds for general corporate purposes.
While industry conditions cannot be predicted with certainty and are
dependent upon a number of commodity and economic factors which are beyond
Contour's control, Contour believes that the cash on hand subsequent to the
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consummation of the above transactions and the recent increase in oil and
natural gas prices, if continued, will sustain its operations over the
short-term. However, Contour will continue to have significant debt outstanding
and limited ability to incur further indebtedness, which, combined with industry
conditions beyond its control, may adversely affect its financial condition,
results of operations and cash flows.
Capital Resources. 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 1999, the Partnership
made quarterly distributions of $0.05, $0.09 and $0.42 per Unit (includes $0.38
per unit related to the proceeds from the sale of properties to Phillips) ,
respectively, (aggregating $12,219,000) as compared to distributions of $0.11,
$0.12 and $0.08 per Unit in March, May and August 1998, respectively
(aggregating $6,734,000). The Partnership intends to continue making quarterly
distributions consistent with its cash distribution policy.
Year 2000. Contour has reviewed and evaluated its Year 2000 issues.
These issues involve the potential disruption to systems, processes, and
business practices that may occur if system hardware and software utilized by
Contour, its vendors, and customers are unable to process year 2000 data.
Contour has worked closely with its information systems and technology
vendors to install updated software, where appropriate, that will be Year 2000
compliant. All of the critical Year 2000 internal systems issues have been
tested and corrected, where necessary.
Contour identified those vendors and others that it believes provide
material services or are vital to its business. Discussions and correspondence
with these companies to determine their Year 2000 readiness have been conducted
throughout 1999 and are essentially complete.
The cost of reviewing and implementing corrective measures for Year
2000 issues to date has not been material to Contour or the Partnership and has
been limited to use of Contour and vendor personnel for review and
implementation of corrective measures. Contour does not expect the remainder of
the Year 2000 review and corrective measures to involve significant costs.
Based on assessments to date and compliance plans in progress,
management is of the opinion that Year 2000 issues, including the cost of
implementing corrective measures, will not have a material impact on the
business or operations of Contour or the Partnership. Nevertheless, as indicated
above, achieving Year 2000 readiness is subject to risk and uncertainties,
especially regarding third parties, and there can be no assurance Contour or the
Partnership will not be adversely affected by 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.
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.
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.
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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, 1998.
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.
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 1999.
11
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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: KELLEY OIL CORPORATION
Managing General Partner
Date: November 15, 1999 By: /s/ Rick G. Lester
-----------------------------------
Rick G. Lester
Chief Financial Officer
(Duly Authorized Officer)
(Principal Accounting Officer)
<PAGE> 14
EXHIBIT INDEX
<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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 0
<SECURITIES> 0
<RECEIVABLES> 916
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 916
<PP&E> 32,528
<DEPRECIATION> 26,921
<TOTAL-ASSETS> 6,523
<CURRENT-LIABILITIES> 176
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 6,347
<TOTAL-LIABILITY-AND-EQUITY> 6,523
<SALES> 2,828
<TOTAL-REVENUES> 4,840
<CGS> 0
<TOTAL-COSTS> 609
<OTHER-EXPENSES> 1,254
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 2,977
<INCOME-TAX> 0
<INCOME-CONTINUING> 2,977
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,977
<EPS-BASIC> 0.14
<EPS-DILUTED> 0.14
</TABLE>
