<PAGE>   1

================================================================================

                                  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. 0-20998



                        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
                                      ---    ---

================================================================================


<PAGE>   2


                KELLEY PARTNERS 1992 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................................  11

PART II.  OTHER INFORMATION..............................................................................  11
</TABLE>



                                       1

<PAGE>   3


                          PART I. FINANCIAL INFORMATION


ITEM 1.  FINANCIAL STATEMENTS

                KELLEY PARTNERS 1992 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 .......................................               12                28
   Accounts receivable - affiliates ..................................              109                 6
                                                                           ------------      ------------
   Total current assets ..............................................              121                34
                                                                           ------------      ------------

   Oil and gas properties, successful efforts method:
     Properties subject to amortization ..............................           44,354            41,466
     Less:  Accumulated depreciation, depletion and amortization .....          (41,826)          (40,367)
                                                                           ------------      ------------
   Total oil and gas properties ......................................            2,528             1,099
                                                                           ------------      ------------
Total assets .........................................................     $      2,649      $      1,133
                                                                           ============      ============

LIABILITIES:
   Accounts payable and accrued expenses .............................     $         98      $         78
                                                                           ------------      ------------

   Total current liabilities .........................................               98                78
                                                                           ------------      ------------

   Long term note payable - affiliate ................................            2,488               210
                                                                           ------------      ------------
Total liabilities ....................................................            2,586               288
                                                                           ------------      ------------

PARTNERS' EQUITY:
   LP Unitholders' equity ............................................              (20)               83
   GP Unitholders' equity ............................................               80               728
   Managing and special general partners' equity .....................                3                34
                                                                           ------------      ------------
Total partners' equity ...............................................               63               845
                                                                           ------------      ------------
Total liabilities and partners' equity ...............................     $      2,649      $      1,133
                                                                           ============      ============
</TABLE>


See Notes to Financial Statements.


                                       2

<PAGE>   4



                KELLEY PARTNERS 1992 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 .......................................     $      369     $      137      $    1,175     $      679
   Gain on sale of properties ..............................             --             --              --            855
                                                                 ----------     ----------      ----------     ----------
   Total revenues ..........................................            369            137           1,175          1,534
                                                                 ----------     ----------      ----------     ----------

EXPENSES:
   Lease operating expenses ................................            112             52             321            247
   Severance taxes .........................................             21             12              65             41
   General and administrative expenses .....................             45             26             111             80
   Interest expenses .......................................             69             61             221            187
   Depreciation, depletion and amortization ................            107             39             317            198
                                                                 ----------     ----------      ----------     ----------
   Total expenses ..........................................            354            190           1,035            753
                                                                 ----------     ----------      ----------     ----------
Net income (loss) ..........................................     $       15     $      (53)     $      140     $      781
                                                                 ==========     ==========      ==========     ==========


Net income (loss) allocable to LP and GP unitholders .......     $       14     $      (51)     $      134     $      750
                                                                 ==========     ==========      ==========     ==========

Net income (loss) allocable to managing and
   special general partners ................................     $        1     $       (2)     $        6     $       31
                                                                 ==========     ==========      ==========     ==========
Net income (loss) per LP and GP unit .......................     $       --     $       --      $      .01     $      .05
                                                                 ==========     ==========      ==========     ==========

Average LP and GP units outstanding ........................         16,033         16,033          16,033         16,033
                                                                 ==========     ==========      ==========     ==========
</TABLE>


See Notes to Financial Statements.



                                       3

<PAGE>   5


                KELLEY PARTNERS 1992 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 ..............................................     $      140      $      781
   Adjustments to reconcile net income to net cash
     provided by operating activities:
     Gain on sale of properties ............................             --            (855)
     Depreciation, depletion and amortization ..............            317             198
   Changes in operating assets and liabilities:
     Decrease in accounts receivable .......................             99              87
     Decrease in accounts payable and accrued expenses .....             (5)            (20)
                                                                 ----------      ----------
   Net cash provided by operating activities ...............            551             191
                                                                 ----------      ----------

INVESTING ACTIVITIES:
   Capital expenditures ....................................             (9)            (16)
   Proceeds from the sale of properties ....................             --           2,103
                                                                 ----------      ----------
   Net cash (used in) provided by investing activities .....             (9)          2,087
                                                                 ----------      ----------

FINANCING ACTIVITIES:
   Principal payments on long-term borrowings ..............           (542)         (2,278)
                                                                 ----------      ----------
   Net cash used in financing activities ...................           (542)         (2,278)
                                                                 ----------      ----------
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

<PAGE>   6


                KELLEY PARTNERS 1992 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 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 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
$2.1 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. In the third quarter of 1999, the sales proceeds were
applied to reduce the Partnership's loan to Kelley Oil.

         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


                                       5

<PAGE>   7

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.

         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.


                                       6

<PAGE>   8



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. (formerly Kelley Oil & Gas
Corporation) ("Contour "), owns 83.72% 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 $2.1 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. In the
third quarter of 1999, the sales proceeds were applied to reduce the
Partnership's loan to Kelley Oil.

         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 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 $25,000 in the third quarter of 1999 and increased
Partnership revenues by approximately $40,000 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
$137,000 for the third quarter of 1999 decreased 63% compared to $369,000 in the
corresponding quarter of 1998 primarily as a result of lower gas production.
Production of natural gas decreased 72% from 168,000 Mcf in the third quarter of
1998 to 47,000 Mcf in the current quarter primarily due to the sale of
properties in the second quarter of 1999 to Phillips Petroleum Company, see
Liquidity and Capital Resources for further discussion. The average price of
natural gas decreased 10% from $2.09 per Mcf in the third quarter of 1998 to
$1.88 per Mcf in the current quarter. Production of crude oil in the current
quarter totaled 2,737 barrels, with an average sales price of $19.10 per barrel
compared to 3,273 barrels at $13.38 per barrel in the same quarter last year,
representing a volume decrease of 16% and a price increase of 43%.



                                       7

<PAGE>   9



         Lease operating expenses and severance taxes were $64,000 in the
current quarter versus $133,000 in the third quarter of 1998, a decrease of 52%.
The decrease was due primarily to lower second quarter 1999 lifting costs
resulting from lower gas production due to the sale of properties in the second
quarter of 1999. On a unit of production basis, these expenses increased to
$1.01 per Mcfe in the third quarter of 1999 from $0.71 per Mcfe in the same
quarter of 1998.

         General and administrative ("G&A") expenses of $26,000 in the current
quarter decreased 42% from $45,000 in the third quarter of 1998. Lower third
quarter 1999 Partnership production activity caused the decline in G&A expenses
charged by Kelley Oil to the Partnership. On a unit of production basis, these
expenses increased from $0.24 per Mcfe in the third quarter of 1998 to $0.41 per
Mcfe in the current quarter.

         Depreciation, depletion and amortization ("DD&A") expenses decreased
64% from $107,000 in the third quarter of 1998 to $39,000 in the current quarter
due to lower current quarter production levels related to the sale of properties
in the second quarter of 1999. On a unit of production basis, DD&A expenses
increased to $0.61 per Mcfe in the third quarter of 1999 from $0.57 per Mcfe in
the same quarter last year.

         The Partnership recognized a net loss of $53,000 or $0.00 per Unit for
the third quarter of 1999. For the third quarter of 1998, the Partnership
recognized net income of $15,000 or $0.00 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
$679,000 for the first nine months of 1999 decreased 42% compared to $1,175,000
in the corresponding period of 1998 as a result of lower gas production and
lower gas and oil prices. Production of natural gas decreased 44% from 511,000
Mcf in the first nine months of 1998 to 285,000 Mcf in the current period
primarily due to the sale of properties to Phillips Petroleum Company. The
average price of natural gas was $2.02 per Mcf in the first nine months of 1999
compared to $2.09 per Mcf in the prior year. Production of crude oil in the
current period totaled 7,689 barrels, with an average sales price of $15.63 per
barrel compared to 7,608 barrels at $14.13 per barrel in the same period last
year, representing a volume increase of 1% and a price increase of 11%. In the
first half of 1999, the Partnership conveyed its interests 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 $855,000; see Liquidity and
Capital Resources for further discussion.

         Lease operating expenses and severance taxes were $288,000 in the
current period versus $386,000 in the first nine months of 1998, a decrease of
25%. The decrease was due primarily to lower lifting costs in the first nine
months of 1999 resulting from lower gas production related to the sale of
properties in the first half of 1999. On a unit of production basis, these
expenses increased to $0.87 per Mcfe in the first nine months of 1999 from $0.70
per Mcfe in the year-earlier period.

         G&A expenses of $80,000 in the current period decreased 28% from
$111,000 in the first nine months of 1998. Lower current period Partnership
production activity caused the decline in G&A expenses charged by Kelley Oil to
the Partnership. On a unit of production basis, these expenses increased from
$0.20 per Mcfe in the first nine months of 1998 to $0.24 per Mcfe in the current
period.

         In the first nine months of 1999 and 1998, the Partnership incurred
interest expenses of $187,000 and $221,000, 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 nine months of 1999. See
"Liquidity and Capital Resources" below.

         DD&A expenses decreased 38% from $317,000 in the first nine months of
1998 to $198,000 in the current period due to lower current period production
levels. On a unit of production basis, DD&A expenses increased to $0.60 per Mcfe
in the first nine months of 1999 from $0.57 per Mcfe in the same period last
year.

                                       8

<PAGE>   10

         The Partnership recognized net income of $781,000 or $0.05 per Unit for
the first nine months of 1999. For the first nine months of 1998, the
Partnership recognized net income of $140,000 or $0.01 per Unit. 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.

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 $191,000. During the period, funds provided by investing
activities included proceeds from the sale of properties to Phillips of
$2,103,000 partially offset by capital expenditures of $16,000, and funds used
in financing activities included a reduction in the Initial Loan principal of
$2,278,000. 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
$2.1 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. In the third quarter of 1999, the sales proceeds were
applied to reduce the Partnership's loan to Kelley Oil.

         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


                                       9

<PAGE>   11

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.

         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 September 30, 1999, $210,000 of the
$6,000,000 Initial Loan remained outstanding. As discussed earlier, the
Partnership's proceeds of $2.1 million from the Phillips transaction were used
to reduce the Partnership's loan. By continuing to service its debt from
operating cash flow, the Partnership expects to further reduce the remaining
outstanding balance of the Initial Loan.

         Year 2000. Contour 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.


                                       10

<PAGE>   12

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, 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

<PAGE>   13


                                   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: November 15, 1999                 By:          /s/ Rick G. Lester
                                             ---------------------------------
                                                      Rick G. Lester
                                                  Chief Financial Officer
                                                 (Duly Authorized Officer)
                                              (Principal Accounting Officer)


                                       12



<PAGE>   14



                                  EXHIBIT INDEX

<TABLE>
<CAPTION>
              EXHIBIT
              NUMBER              DESCRIPTION
              -------             -----------
<S>                      <C>
               27        Financial Data Schedule (included only in the
                         electronic filing of this document).
</TABLE>