##### Table of Contents

---




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 June 30, 2002

Commission File No. 0-20998





---




KELLEY PARTNERS 1992 DEVELOPMENT


DRILLING PROGRAM


(Exact name of registrant as specified in its charter)





Texas (State or other
jurisdiction of incorporation or organization)

76-0373428 (I.R.S.
Employer Identification No.)1001 McKinney St. Suite
900 Houston, Texas (Address of principal executive
offices)

77002 (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  ̈





---



---

##### Table of Contents




KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM





INDEX





PagePart I.    Financial InformationItem 1.    Financial Statements:Balance Sheets as of December 31, 2001 and June 30, 2002 (unaudited)

2Statements of Income for the three months and six months ended June 30, 2001 and 2002(unaudited)

3Statements of Cash Flows for the six months ended June 30, 2001 and 2002 (unaudited)

4Notes to Financial Statements (unaudited)

5Item 2.    
Managements Discussion and Analysis of Financial Condition and Results of Operations

6Part II.    
Other Information

10




1




---

##### Table of Contents




PART I.    FINANCIAL INFORMATION





Item 1.Financial Statements





KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM


BALANCE SHEETS


(In thousands)





December 31, 2001


June 30, 2002(Unaudited)Assets:Cash and cash equivalents

$



$
Accounts receivabletrade


12



Accounts receivableaffiliates


127



154Total current assets


139



154Oil and gas properties, successful efforts method:Properties subject to amortization


41,461



41,461Less: Accumulated depreciation, depletion and amortization


(40,593
)


(40,637
)Total oil and gas properties


868



824Total assets

$
1,007


$
978Liabilities:Accounts payable and accrued expenses

$
47


$
27Total current liabilities


47



27Total liabilities


47



27Partners Equity:LP Unitholders equity


70



69GP Unitholders equity


851



844Managing and special general partners equity


39



38Total partners equity


960



951Total liabilities and partnersequity

$
1,007


$
978





See Notes to Financial Statements.







2




---

##### Table of Contents




KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM


STATEMENTS OF INCOME


(In thousands, except per unit data)


(Unaudited)





Three Months Ended June
30,

Six Months Ended June
30,2001

2002

2001

2002Revenues:Oil and gas sales

$
219

$
163

$
527

$
260Total revenues


219


163


527


260Expenses:Production expenses


47


71


88


96Severance taxes


3


12


5


21General and administrative expenses


16


10


26


19Depreciation, depletion and amortization


20


24


42


44Total expenses


86


117


161


180Net income

$
133

$
46

$
366

$
80Net income allocable to LP and GP unitholders

$
128

$
44

$
352

$
77Net income allocable to managing and special general partners

$
5

$
2

$
14

$
3Net income per LP and GP unit

$
.01

$
.00

$
.02

$
.00Average LP and GP units outstanding


16,033


16,033


16,033


16,033








See Notes to Financial Statements.




3




---

##### Table of Contents




KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM


STATEMENTS OF CASH FLOWS


(In thousands)


(Unaudited)





Six months Ended June
30,2001


2002Operating Activities:Net income

$
366


$
80Adjustments to reconcile net income to net cash provided by operating activitiesDepreciation, depletion and amortization


42



44Changes in operating assets and liabilities:Increase in accounts receivable


(267
)


(15
)Decrease in accounts payable and accrued expenses


(32
)


(20
)Net cash provided by operating activities


109



89Investing Activities:Capital expenditures


(20
)


Net cash used in investing activities


(20
)


Financing Activities:Distribution to partners


(89
)


(89
)Net cash used in financing activities


(89
)


(89
)Increase (decrease) in cash and cash equivalents






Cash and cash equivalents, beginning of period






Cash and cash equivalents, end of period

$



$









See Notes to Financial Statements.




4




---

##### Table of Contents




KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM


NOTES TO FINANCIAL STATEMENTS (UNAUDITED)





NOTE 1BASIS OF PRESENTATION





General.    The accompanying unaudited interim financial statements of Kelley Partners 1992 Development
Drilling Program (the Partnership) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission in accordance with accounting principles generally accepted in the United States of America for interim
financial information. These financial statements reflect all adjustments (consisting solely of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods presented. The results of operations for the three
and six months ended June 30, 2002 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 3 to the financial statements included in its Annual Report on
Form 10-K for the year ended December 31, 2001. These unaudited interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnerships 2001 Annual Report on Form 10-K.





NOTE 2GENERAL PARTNER





Contour Energy E&P, LLC, managing general partner of the Partnership (Contour E&P), owns 91.86% of the Partnership units, plus a 3.94% managing general partnership interest at June
30, 2002. Contour E&P is a subsidiary of Contour Energy Co. (collectively with its subsidiaries, Contour or the Company).





On July 15, 2002, Contour Energy Co. announced that it filed in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the Bankruptcy Court), a petition
for reorganization under Chapter 11 of the United States Bankruptcy Code, Case No. 02-37740-H2-11. Contour E&P (Case No. 02-37741-H2-11), and Kelley Operating Company, Ltd., (Case No. 02-37744-H2-11), a joint venturer with the Partnership,
(Kelley Operating), also filed Chapter 11 petitions with the Bankruptcy Court on that day. Following extensive negotiations with an informal committee of holders of more than 75% of their 10 3/8% subordinated notes (the Ad Hoc
Committee), the Company and its subsidiaries filed a Joint Plan of Reorganization (the Plan) and a Disclosure Statement regarding the Plan with the Bankruptcy Court embodying the terms of a proposed restructuring of Contour and its
affiliates. The Bankruptcy Court has not approved the Plan, and the Company cannot give any assurance that the Bankruptcy Court will approve the Plan in its current form.





As a result of the Contour E&P and Kelley Operating chapter 11 filings, a dissolution event has occurred under the limited partnership agreement governing the
Partnership. The Partnership may be continued at the election of Unitholders holding a majority of the outstanding units. Contour E&P, as majority holder of the units, does not intend to take action to continue the Partnership.





With the Chapter 11 filing of Kelley Operating, a dissolution event has also occurred under the joint venture agreement
pursuant to which properties of the Partnership are managed. Accordingly, the Partnership and the business of the Partnerships joint venture with Kelley Operating shall be wound up and their respective assets distributed in accordance with the
terms of the governing agreements. With the pendency of the Companys Chapter 11 proceedings, the timing of winding up the affairs of the Partnership and the distribution of its assets is uncertain at this time. The accompanying unaudited
interim financial statements of the Partnership have been prepared using the historical cost basis of accounting without further adjustments that maybe required if the Partnership is liquidated.





NOTE 3NEW ACCOUNTING PRONOUNCEMENTS





In
August and October 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations and SFAS No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. SFAS 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the




5




---

##### Table of Contents

asset retirement costs should be allocated to expense using a systematic and rational method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses financial
accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
of, and is effective for fiscal years beginning after December 15, 2001. The Partnership continues to assess the impact of SFAS No. 143 and cannot yet reasonably estimate the impact, if any, this statement will have on its financial statements
upon adoption. The Partnership expects no impact to its financial statements upon the adoption of SFAS 144.





In
April 2002, the Financial Accounting Standards Board (FASB) issued SFAS 145 Rescission of FASB Statements No. 4, No. 44 and No. 64, Amendment to FASB Statement No. 13 and Technical Corrections. SFAS No. 145 streamlines the
reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in Accounting Policies Board Opinion 30 would be classified as extraordinary. Thus gains or losses arising from extinguishments that
are part of a companys recurring operations would not be reported as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. The Partnership does not expect the adoption of SFAS No. 145 to have an impact
on its financial position, results of operations or cash flows.





SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities was issued in June 2002 and addresses accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (ETIF) issue No. 94-3,
Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit and Activity (including Certain Costs Incurred in a Restructuring), SFAS No. 146 requires that a liability for a cost associated with an exit or
disposal activity be recognized when the liability is incurred. Under Issue 94-3, a liability for an exit costs was recognized at the date of an entitys commitment to an exit plan. Under SFAS No. 146, fair value is the objective for initial
measurement of the liability. SFAS No. 146 is effective for exit disposal activities that are initiated after December 31, 2002. The Partnership does not expect the adoption of SFAS No. 146 to have an impact on its financial position, results of
operations or cash flows.





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. At June 30, 2002, Contour Energy E&P, LLC, managing general partner of the Partnership (Contour E&P) and a wholly owned subsidiary of Contour Energy Co.
(collectively with its subsidiaries, Contour or the Company) owns 91.86% of the Units and a 3.94% managing general partnership interest.





Subsequent Events





On July 15, 2002, Contour Energy
Co. and certain of its affiliates, including Contour E&P, the managing general partner of the Partnership, and Kelley Operating, a joint venturer with the Partnership, filed voluntary petitions under chapter 11 of the United States Bankruptcy
Code. As a result of these filings, a dissolution event has occurred under the limited partnership agreement governing the Partnership. The Partnership may be continued at the election of Unitholders holding a majority of the outstanding units.
Contour E&P, as majority holder of the units, does not intend to take action to continue the Partnership.





With the Chapter 11 filing of Kelley Operating, a dissolution event has also occurred under the joint venture agreement pursuant to which properties of the Partnership are managed. Accordingly, the Partnership and the business of the
Partnerships joint venture with Kelley Operating shall be wound up and their respective assets




6




---

##### Table of Contents

distributed in accordance with the terms of the governing agreements. With the pendency of the Companys Chapter 11 proceedings, the timing of winding up the affairs of the Partnership and
the distribution of its assets is uncertain at this time.





Results of Operations





Three Months Ended June 30, 2002 and 2001.    Oil and gas revenues decreased 26% to $163,000 for the
second quarter of 2002 compared to $219,000 in the corresponding quarter of 2001, primarily the result of lower natural gas production and lower natural gas and crude oil prices, partially offset by higher crude oil production. Production of natural
gas decreased 17% from 34,726 Mcf in the second quarter of 2001 to 28,809 Mcf in the current quarter primarily due to normal production declines in the Partnerships producing areas. The average price of natural gas decreased 23% from $4.97 per
Mcf in the second quarter of 2001 to $3.81 per Mcf in the current quarter. Production of crude oil in the current quarter totaled 2,167 barrels, with an average sales price of $25.57 per barrel compared to 1,689 barrels, with an sales average price
of $27.98 per barrel, in the same quarter last year, representing a volume increase of 28% and a price decrease of 9%.





Production expenses and severance taxes were $83,000 in the current quarter versus $50,000 in the second quarter of 2001, an increase of 66%. The second quarter 2002 includes $25,000 for insurance costs due to increased policy
premiums for the period May 2001 through May 2002. The Partnership also experienced higher severance taxes during the current quarter due to a higher tax rate on natural gas imposed by the state of Louisiana in July 2001. As a result of these
factors and lower equivalent production volumes in the current quarter, production expenses and severance taxes on a per unit of production basis increased from $1.11 per Mcfe in the second quarter of 2001 to $1.99 per Mcfe in the current quarter.
Excluding the increase in insurance cost, per unit of production cost would have been $1.39 per Mcfe for the current quarter.





General and administrative (G&A) expenses decreased 38% to $10,000 in the current quarter from $16,000 in the second quarter of 2001. Lower second quarter 2002 production volumes caused a decline in G&A expenses
charged by Contour E&P to the Partnership. On a unit of production basis, these expenses were $0.24 per Mcfe for the second quarter of 2002 compared to $0.36 per Mcfe for the second quarter of 2001, a 33% decrease.





Depreciation, depletion and amortization (DD&A) expenses increased 20% to $24,000 in the second quarter of 2002 from
$20,000 in the second quarter of 2001, primarily the result of a higher composite DD&A rate as proportionally higher volumes of production were produced from higher DD&A rate fields. On a unit of production basis, DD&A expense was $0.57
per Mcfe in the second quarter of 2002 compared to $0.45 per Mcfe in the same quarter last year, an increase of 27%.





The Partnership recognized net income of $46,000 or $0.00 per Unit for the second quarter of 2002. For the second quarter of 2001, the Partnership recognized net income of $133,000 or $0.01 per Unit. The reasons for the variance
between the second quarter of 2002 and the second quarter of 2001 are described in the foregoing discussion.





Six Months Ended June 30, 2002 and 2001.    Oil and gas revenues decreased 51% to $260,000 for the first six months of 2002 compared to $527,000 in the corresponding period of 2001 as a result of lower
natural gas and crude oil production and lower natural gas and crude oil prices. Production of natural gas decreased 21% from 67,087 Mcf in the first six months of 2001 to 52,680 Mcf in the current period primarily due to normal production declines
in the Partnerships producing areas. The average price of natural gas was $6.32 per Mcf in the first half of 2001 compared to $3.26 per Mcf in first six months of 2002, a decrease of 48%. Production of crude oil in the current period totaled
3,850 barrels, with an average sales price of $23.80 per barrel compared to 3,860 barrels priced at an average price of $27.29 per barrel in the same period last year, representing nearly flat production volumes and a price decrease of 13%.




7




---

##### Table of Contents




Production expenses and severance taxes were $117,000 in the current period
versus $93,000 in the first half of 2001, an increase of 26%. The first six months of 2002 includes $25,000 for insurance costs due to increased policy premiums for the period May 2001 through May 2002. The Partnership also experienced higher
severance taxes during the first half of 2002 due to a higher tax rate on natural gas imposed by the state of Louisiana in July 2001. On a unit of production basis, these expenses increased to $1.55 per Mcfe in the first six months of 2002 from
$1.03 per Mcfe in the year-earlier period. Excluding the increase in insurance cost, per unit of production cost would have been $1.21 per Mcfe for the current quarter.





G&A expenses decreased 27% to $19,000 in the current period from $26,000 in the first half of 2001. Lower current period production activity caused the decline in
G&A expenses charged by Contour E&P to the Partnership. On a unit of production basis, these expenses decreased from $0.29 per Mcfe in the first six months of 2001 to $0.25 per Mcfe in the current period.





DD&A expenses increased 5% from $42,000 in the first six months of 2001 to $44,000 in the current period primarily the result of a
higher composite DD&A rate as proportionally higher volumes of production were produced from higher DD&A rate fields, partially offset by lower equivalent production. On a unit of production basis, DD&A expense increased to $0.58 per
Mcfe in the first half of 2002 from $0.47 per Mcfe in the same period last year.





The Partnership recognized net
income of $80,000 or $0.00 per Unit for the first half of 2002. For the first half of 2001, the Partnership recognized net income of $366,000 or $0.02 per Unit. The reasons for the variance between the first six months of 2002 and the first six
months of 2001 are described in the foregoing discussion.





The results of operations for the quarter and six
months ended June 30, 2002 are not necessarily indicative of the Partnerships operating results to be expected for the full year.





Liquidity and Capital Resources





Liquidity.    The Partnership generated $89,000 of cash flows from its operating activities during the first six months of 2002, as reflected on its statement of cash flows. Additionally, no cash was
provided by or used in its investing activities during the period. The Partnership made distributions of $89,000 to its partners in the first half of 2002 and as a result the Partnerships cash and cash equivalents remained unchanged from
December 31, 2001.





Commodity Prices.    The Partnership experienced weak commodity
prices during the first three months of 2002 with average realized prices for natural gas and crude oil of $2.58/Mcf and $21.53/Bbl, respectively. Commodity prices strengthened in the second quarter of 2002 with average realized prices for natural
gas and crude oil of $3.81/Mcf and $25.57/Bbl, respectively. However, prices have weakened recently with the price for August natural gas falling again below $3.00/Mmbtu on the NYMEX. Storage levels for natural gas remain at historically high levels
and the strength and timing of improvement in demand for natural gas is uncertain.





Capital
Resources.    The Partnership has completed its development stage. Accordingly, capital and general working capital needs should be minimal.





Although the capital needs of the Partnership are minimal and are funded by cash flows from operations, the administration of the Partnership and its assets are dependent
on Contour E&P as Managing General Partner. The financial difficulties that lead to Contours bankruptcy filing (see Note 2 to the Notes to the Financial Statements) could have a detrimental effect on Contour E&Ps abilities to
administer the Partnership.





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. During the first half of 2002, $89,000 was distributed to the Partnerships Unitholders and the managing and special
general partners. Future distributions to the Unitholders and the managing and special general partners are contingent on future operating results.




8




---

##### Table of Contents




Inflation and Changing Prices.    Oil and natural gas
prices, as with most commodities, are highly volatile, have fluctuated during recent years and generally have not followed the same pattern as inflation.





Accounting Pronouncements.    In August and October 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations and SFAS No. 144,
Accounting for Impairment or Disposal of Long-Lived Assets. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the
carrying amount of the related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic and rational method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses
financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of, and is effective for fiscal years beginning after December 15, 2001. The Partnership is currently assessing the impact of SFAS No. 143 and cannot yet reasonably estimate the impact, if any, this statement will have on its
financial statements upon adoption. The Partnership expects no impact to its financial statements upon the adoption of SFAS 144.





In April 2002, the Financial Accounting Standards Board (FASB) issued SFAS 145 Rescission of FASB Statements No. 4, No. 44 and No. 64, Amendment to FASB Statement No. 13 and Technical Corrections. SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in Accounting Policies Board Opinion 30 would be classified as extraordinary. Thus gains or losses arising from
extinguishments that are part of a companys recurring operations would not be reported as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. The Partnership does not expect the adoption of SFAS No.
145 to have an impact on its financial position, results of operations or cash flows.





SFAS No. 146,
Accounting for Costs Associated with Exit or Disposal Activities was issued in June 2002 and addresses accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force
(ETIF) issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit and Activity (including Certain Costs Incurred in a Restructuring), SFAS No. 146 requires that a liability for a
cost associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue 94-3, a liability for an exit costs was recognized at the date of an entitys commitment to an exit plan. Under SFAS No. 146, fair value
is the objective for initial measurement of the liability. SFAS No. 146 is effective for exit disposal activities that are initiated after December 31, 2002. The Partnership does not expect the adoption of SFAS No. 146 to have an impact on its
financial position, results of operations or cash flows.





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 statement within
the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, relating to matters such as anticipated operating and financial performance, business prospects, developments
and results of the Partnership. Actual performance, prospects, developments and results may differ materially from any or all anticipated results due to economic conditions and other risks, uncertainties and circumstances partly or totally outside
the control of the Partnership, including rates of inflation, oil and natural gas prices, uncertainty of reserve estimates, rates and timing of future production of oil and natural gas, exploratory and development activities, acquisition risks,
changes in the level and timing of future costs and expenses related to drilling and operating activities and those risk factors described on pages 10 and 11 of the Partnerships Annual Report on Form 10-K for the fiscal year ended December 31,
2001.





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




---

##### Table of Contents

PART II.    
OTHER INFORMATION





Item 6.Exhibits and Reports on Form 8-K





(a)  Exhibits:





Exhibit Number:

Exhibit*99.1

Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.*99.2

Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002


---

|* |  | filed herewith.
|- |  | ---------------




(b)  Reports on Form 8-K:





No reports on Form 8-K were filed by the Registrant during
the second quarter of 2002.




10




---

##### Table of Contents

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 PROGRAMBy:

CONTOUR ENERGY E&P, LLCManaging General PartnerDate: August 22, 2002



By:

/s/    RICK G.
LESTERRick G. Lester Manager




11