Item 3. Legal Proceedings
Contour, through its subsidiaries, is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability thereunder, if any, will not have a material effect on the financial condition of Contour E&P or the Partnership.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
Item 5.
Item 5. Market for Units and Related Unitholder Matters
There is no market for the Units of the Partnership. Transfer of the Units was substantially restricted by the provisions of the Partnership Agreement until the Partnership Agreement was amended in December 2000 to allow unitholders to buy or sell units from existing unitholders. As of March 22, 2002, there were 471 holders of record of the Partnership's Units.
The following table sets forth the cash distributions per Unit paid by the Partnership during the periods indicated.
Distribution levels are affected by numerous factors, including oil and gas prices, production levels and operating costs, together with any working capital or debt service requirements. To enable the Partnership to fund part of its drilling and recompletion expenses in excess of contributed capital, distributions were suspended in the fourth quarter of 1994 and reinstated only for the third quarter of 1995. In the third quarter 2000, the final payment on the $6,000,000 Initial Loan from Contour E&P was paid. The Partnership made distributions for the year 2001 aggregating $435,000 to the unitholders, or $0.03 per Unit, and $18,000 to the Managing and Special General Partners for their interest. Future distributions to the unitholders and the managing and special general partners are contingent on future operating results. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Item 6.
Item 6. Selected Financial Data
The following table presents selected financial data for the Partnership. The financial information presented below is derived from the Partnership's audited Financial Statements presented elsewhere in this Report and in previously filed Form 10Ks, and should be read in conjunction with those Financial Statements and the related Notes thereto.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM (In thousands, except per unit amounts)
- -------- (1) Total Revenues and Production expenses have been restated for the years 1997, 1998 and 2000 in accordance with accounting pronouncement EITF 00-10 issued in 2000. (2) Per Unit amounts are based on the Unitholders' 96.04% share of net income and loss. (3) 1999 revenues include gain on sale of properties of $850.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
In 1992, the Partnership issued a total of 16,033,009 units of limited and general partner interests ("Units") at $3.00 per Unit for a total of $48,099,027. The Units represent 96.04% of the total interests in the Partnership and consist of 1,647,500 Units of limited partner interests ("LP Units") and 14,385,509 Units of general partner interests ("GP Units") at December 31, 2001. In addition, the Partnership issued managing and special general partner interests on a pro rata basis for $1,983,258, representing 3.96% of the total interests in the Partnership. In the aggregate, Contour Energy E&P, LLC (formerly Kelley Oil Corporation), a Delaware corporation, the Managing General Partner of the Partnership ("Contour E&P"), owns 91.86% of the Units and a 3.94% general partner interest at December 31, 2001. Contour E&P is a subsidiary of Contour Energy Co., collectively with its subsidiaries ("Contour").
In December 2000, Contour E&P invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for all of the Partnership units not held by Contour E&P. A total of 1,298,724 Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs.
In 2001, Kelley Oil Corporation, the Managing General Partner of the Partnership converted to a Delaware limited liability company and changed its name to Contour Energy E&P, LLC.
General Partner. Contour's 14% senior secured notes totaling $105 million becomes due by April 15, 2003. Contour E&P is a guarantor under these notes. Redemption of these notes begins in 2002 with $2.1 million principal payments due in July and October. An additional redemption payment of $2.1 million is due in January 2003 with a final payment of $98.7 million due on April 15, 2003. It is not anticipated that Contour will generate sufficient cash flows from operations to repay this debt. Neither can it assume that future borrowings will be available in an amount sufficient to pay or refinance this obligation on commercially reasonable terms or at all. Failure to repay or refinance the debt as it matures would result in a default under the indenture.
Contour has entered into discussions with certain of its debt holders that may lead to a restructuring transaction. The outcome of the negotiations and the possible impact on the Partnership are uncertain. However, if negotiations are not successful. Contour may be forced to seek protection under federal bankruptcy regulations. Contour E&P is a guarantor under the 14% senior secured notes. A potential default under these notes or a bankruptcy filing by Contour could have a material adverse impact on the Partnership.
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. Historically, Contour periodically entered into hedge contracts to protect against commodity price declines on behalf of the Partnership. Contour normally employs the average NYMEX price for the last three days of the contract for natural gas and the monthly average of closing NYMEX prices for crude oil as the underlying index ("Index Price") See Note 6 in the Notes to the Financial Statements. However, effective 2001 the Partnership no longer plans to enter into hedging transactions because small production volumes makes doing so no longer feasible.
Through natural gas price swap agreements, the Partnership hedged approximately 50% of its natural gas production for 1999 at average NYMEX quoted price of $2.17/Mmbtu, before transaction and transportation costs. For 2000, the Partnership hedged approximately 72% of its natural gas production using price swap agreements (48%) and a costless collar (24%). The average price received under the swap agreements was $2.59/Mmbtu. The costless collar included a ceiling of $4.98/Mmbtu and a floor of $4.00/Mmbtu at the closing Index Price.
Through crude oil price swap agreements, the Partnership hedged approximately 29% of its crude oil production for 1999 at an average NYMEX quoted price of $20.00 /Bbl, before transaction and transportation costs. For 2000, the Company hedged approximately 66% of its crude oil production using price swap
agreements (41%) and costless collars (25%). The average price received under the swap agreements was $26.21/Bbl. The costless collars included an average ceiling of $32.21/Bbl and an average floor of $26.11/Bbl at the closing Index Price.
Hedging activities decreased Partnership oil and natural gas revenues by approximately $17,000 and $109,000 in 1999 and 2000, respectively as compared to estimated revenues had no hedging activities been conducted.
The credit risk exposure from counterparty nonperformance on natural gas forward sales contracts and derivative financial instruments is generally the amount of unrealized gains under the contracts. The Partnership has not experienced counterparty nonperformance on these agreements.
Critical Accounting Policies
Introduction. The forgoing describes the critical accounting policies used by the Partnership in reporting its financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting, such is the case with accounting for oil and gas activities described below. In those cases, the Partnership's reported results of operations would be different should it employ an alternative accounting method.
Successful Efforts Method of Accounting for Oil and Gas Activities. The Securities and Exchange Commission ("SEC") prescribes in Regulation SX the financial accounting and reporting standards for companies engaged in oil and gas producing activities. Two methods are prescribed: the successful efforts method and the full cost method. Like many other oil and gas companies, the Partnership has chosen to follow the successful efforts method.
Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit of production basis over the life of the related reserves. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are amortized on a unit of production basis over the life of the related reserves. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred.
In accordance with accounting under successful efforts, the Partnership reviews proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. The Partnership's oil and gas reserves are mature, but still have a relatively long life. However, even a temporary drop in prices can have a material impact on its business.
Estimated Abandonment or Site Restoration. The estimated costs of future abandonment and site restoration, net of anticipated salvage values, are amortized on a unit-of-production basis over the life of the related reserves. The amortization of these costs is included on the Partnership's Statements of Income under depreciation, depletion and amortization expense.
Derivative Instruments and Hedging Activities. The Partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows, then the changes in fair value of the derivative instrument will generally be reported in Other Comprehensive Income ("OCI").
At of January 1, 2001, the Partnership was not party to any derivative instruments and as such there was no impact on its financial statements as a result of the adoption of SFAS 133. During and at year-end 2001, the Partnership did not and was not participating in any derivative instruments.
Results of Operations
Years Ended December 31, 2001 and 2000. Oil and gas revenues were $817,000 for 2001 as compared to $800,000 in the corresponding period of 2000, primarily as a result of higher natural gas prices partially offset by lower oil and gas production. Production of natural gas decreased 14% from 149,000 Mcf in 2000 to 128,000 Mcf in 2001. Production of crude oil in the current year totaled 8,598 barrels compared to 9,031 barrels last year, representing a decrease of 5%. Oil and gas production decreased due normal declines in the Partnership's producing areas.
Lease operating expenses and severance taxes were $209,000 in 2001 versus $256,000 in 2000, a decrease of 18%, primarily related lower production and lower lifting costs per equivalent production unit. Lower lifting costs were partially offset by an increase in severance tax expense on a per unit basis resulting from a rate increase in Louisiana. On a unit of production basis, these expenses decreased to $1.16 per Mcfe in 2001 from $1.26 per Mcfe in 2000.
General and administrative ("G&A") expenses of $44,000 in 2001 decreased 29% from $62,000 in 2000. On a unit of production basis, these expenses decreased from $0.31 per Mcfe in 2000 to $0.24 per Mcfe in 2001. As the Partnership's production declines it receives a smaller allocation of G&A costs from Contour Energy E&P.
In 2000, the Partnership incurred interest expense of $6,000 on a loan advanced to it by Contour E&P in August 1994 to fund part of its drilling expenses in excess of contributed capital. In 2000, the final payment of $166,000 was made on the $6,000,000 Initial Loan.
Depreciation, depletion and amortization ("DD&A") expense decreased 36% from $120,000 in 2000 to $77,000 in 2001 due to lower production levels and lower composite depletion rates. On a unit of production basis, DD&A expense decreased 27% from $0.59 per Mcfe in 2000 to $0.43 per Mcfe in 2001.
The Partnership recognized net income in 2001 of $487,000 or $0.03 per Unit compared to net income in 2000 of $356,000, or $0.02 per Unit. The reasons for the variance between 2001 and 2000 are described in the foregoing discussion.
Years Ended December 31, 2000 and 1999. Oil and gas revenues were $800,000 for 2000 as compared to $843,000 in the corresponding period of 1999, primarily as a result of lower oil and gas production offset by higher oil and natural gas prices. Production of natural gas decreased 53% from 314,000 Mcf in 1999 to 149,000 Mcf in 2000. Production of crude oil in the current year totaled 9,031 barrels compared to 9,398 barrels last year, representing a decrease of 4%. Oil and gas production decreased due to the sale of properties to Phillips Petroleum Company ("Phillips") in the second quarter of 1999 and natural depletion.
Lease operating expenses and severance taxes were $256,000 in 2000 versus $378,000 in 1999, a decrease of 32%, primarily related to the sale of properties to Phillips. On a unit of production basis, these expenses increased to $1.26 per Mcfe in 2000 from $1.02 per Mcfe in 1999. Transportation and compression expenses of $48,000 ($0.13 per Mcfe) and $7,000 ($0.03 per Mcfe) were included in lease operating expense for 1999 and 2000, respectively, as a result of accounting pronouncement EITF 00-10 issued in 2000.
G&A expenses of $62,000 in 2000 decreased 33% from $92,000 in 1999. On a unit of production basis, these expenses increased from $0.25 per Mcfe in 1999 to $0.31 per Mcfe in 2000.
In 2000 and 1999, the Partnership incurred interest expense of $6,000 and $174,000, respectively, on a loan advanced to it by Contour E&P in August 1994 to fund part of its drilling expenses in excess of contributed capital. The reduction reflects the lower average note payable balance outstanding in 2000 as compared to 1999. In 2000, the final payment of $166,000 was made on the $6,000,000 Initial Loan. See "Liquidity and Capital Resources".
DD&A expense decreased 47% from $225,000 in 1999 to $120,000 in 2000 due to lower production levels related to the sale of properties to Phillips and lower depletion rates. On a unit of production basis, DD&A expense decreased from $0.61 per Mcfe in 1999 to $0.59 per Mcfe in 2000.
The Partnership recognized net income in 2000 of $356,000 or $0.02 per Unit compared to net income in 1999 of $824,000, including a $850,000 gain on sale of properties, or $0.05 per Unit. The reasons for the variance between 2000 and 1999 are described in the foregoing discussion.
Liquidity and Capital Resources
Liquidity. Net cash provided by the Partnership's operating activities during 2001, as reflected on its statement of cash flows, totaled $471,000. During the period, funds used in investing activities totaled $18,000 in capital expenditures and funds used in financing activities were for partnership distributions of $453,000. As a result of these activities, the Partnership's cash and cash equivalents remained at zero at December 31, 2001.
During the first half of 2001, the Partnership benefited from an increase in the level of commodity prices compared to historic levels. However, cash prices and NYMEX based prices for both oil and natural gas have declined significantly during the second half of 2001 and early 2002, reflecting the volatility of commodity prices. Natural gas prices over the past six months have averaged below $2.50/Mcf and crude prices have averaged below $20.00/bbl. Sustained prices at these levels or lower could have a materially adverse impact on the Partnership's results of operations and its ability to make future distributions. Historically, Contour on behalf of the Partnership periodically enters into hedge contracts to protect against commodity price declines. However, effective 2001 the Partnership no longer participated in hedging transactions due to its relatively small production volumes.
Capital Resources. The partners' equity at December 31, 2001 increased to $960,000 as compared to $926,000 at December 31, 2000. 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. As of December 31, 2001, the Partnership was fully capitalized with contributions aggregating $50,082,285.
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 of Contour could have a detrimental effect on its 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 2001, current year earnings distributions were paid to the managing and special general partners and the unitholders in the amounts of $18,000 and $435,000, or $0.03 per Unit, respectively. However, future distributions to the unitholders and the managing and special general partners are contingent on future operating results.
Related Party Transactions. The Unitholders have a 96.04% share and the general partners a 3.96% share in the costs and revenues of the Partnership. The Partnership reimburses Contour E&P for all direct costs incurred in managing the Partnership and all indirect costs (principally general and administrative expenses) allocable to the Partnership.
Overhead allocated to the Partnership by Contour E&P for the years ended December 31, 1999, 2000 and 2001 related to general and administrative expenses aggregated $92,000, $62,000 and $44,000, respectively.
Substantially all of the Partnership's gas sales are made to an affiliated company, Concorde Gas Marketing, Inc.("CGM"), an indirect wholly-owned subsidiary of Contour E&P, which remarkets gas to third parties. For 1999, 2000 and 2001, a fee of 2% of the resale price was charged to the Partnership by CGM for its marketing services.
In December 2000, Contour E&P invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for all of the Partnership units not held by Contour E&P. A total of 1,298,724
Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs. After the tender, Contour E&P owned 91.82% of the Units and a 3.94% General Partner interest.
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. The following table shows the changes in the average oil and natural gas prices (including the effects of hedging) received by Partnership during the periods indicated.
Accounting Pronouncements. The Partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The Partnership was not party to any derivative instruments during 2001 and as such there was not impact from the adoption of SFAS 133.
In July 2001, the Financial Accounting Standards Board ("FASB") issued two new pronouncements: Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS 142, effective for fiscal years beginning after December 15, 2001, addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, Intangible Assets. It addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. This Statement also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The Partnership expects no impact on its financial statements from the adoption of these standards.
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 statements will have on its financial statements upon adoption. The Partnership expects no impact on its financial statements from the adoption of SFAS 144.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
See discussion in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations-Hedging".
Item 8.
Item 8. Financial Statements and Supplementary Data
INDEPENDENT AUDITORS' REPORT
To the Partners of Kelley Partners 1992 Development Drilling Program:
We have audited the accompanying balance sheets of Kelley Partners 1992 Development Drilling Program (a Texas limited partnership) as of December 31, 2000 and 2001, and the related statements of income, cash flows, and changes in partners' equity (deficit) for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Kelley Partners 1992 Development Drilling Program as of December 31, 2000 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements for the year ended December 31, 2001 have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the financial statements, the parent of the Managing General Partner is attempting to negotiate a restructuring of its long-term debt which could lead to a filing for bankruptcy protection under federal bankruptcy regulations. This raises substantial doubt about the Partnership's ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
DELOITTE & TOUCHE LLP
Houston, Texas March 7, 2002 (April 15, 2002 as to Note 2)
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
BALANCE SHEETS (In thousands)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF INCOME (In thousands, except per unit data)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CASH FLOWS (In thousands)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
STATEMENTS OF CHANGES IN PARTNERS' EQUITY (DEFICIT) (In thousands)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS
NOTE 1--ORGANIZATION AND MANAGEMENT
In 1992, the Partnership issued a total of 16,033,009 units of limited and general partner interests ("Units"). The Units represent 96.04% of the total interests in the Partnership and consist of 1,647,500 Units of limited partner interests ("LP Units") and 14,385,509 Units of general partner interests ("GP Units") at December 31, 2001. In addition, the Partnership issued managing and special general partner interests on a pro rata basis representing 3.96% of the total interests in the Partnership. In the aggregate, Contour Energy E&P, LLC (formerly Kelley Oil Corporation), a Delaware corporation, the Managing General Partner of the Partnership ("Contour E&P"), owns 91.86% of the Units and a 3.94% general partner interest at December 31, 2001. Contour E&P is a subsidiary of Contour Energy Co., collectively with its subsidiaries ("Contour").
In December 2000, Contour E&P invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for all of the Partnership units not held by Contour E&P. A total of 1,298,724 Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs.
In 2001, Kelley Oil Corporation, the Managing General Partner of the Partnership converted to a Delaware limited liability company and changed its name to Contour Energy E&P, LLC.
NOTE 2--GENERAL PARTNER
Contour's 14% senior secured notes totaling $105 million becomes due by April 15, 2003. Contour E&P is a guarantor under these notes. Redemption of these notes begins in 2002 with $2.1 million principal payments due in July and October. An additional redemption payment of $2.1 million is due in January 2003 with a final payment of $98.7 million due on April 15, 2003. It is not anticipated that Contour will generate sufficient cash flows from operations to repay this debt. Neither can it assume that future borrowings will be available in an amount sufficient to pay or refinance this obligation on commercially reasonable terms or at all. Failure to repay or refinance the debt as it matures would result in a default under the indenture.
Contour has entered into discussions with certain of its debt holders that may lead to a restructuring transaction. The outcome of the negotiations and the possible impact on the Partnership are uncertain. However, if negotiations are not successful, Contour may be forced to seek protection under federal bankruptcy regulations. Contour E&P is a guarantor under the 14% senior secured notes. A potential default under these notes or a bankruptcy filing by Contour could have a material adverse impact on the Partnership.
NOTE 3--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents. The Partnership considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents.
Income Taxes. The income or loss of the Partnership for federal income tax purposes is includable in the tax returns of the individual partners of the Partnership. Accordingly, no recognition has been given to income taxes in the accompanying financial statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS--(Continued)
Oil and Gas Properties. Oil and gas properties are located in the United States, and are held of record by Kelley Operating Company, Ltd., a subsidiary of Contour E&P. The Partnership utilizes the successful efforts method of accounting for its oil and gas operations. Under the successful efforts method, the costs of successful wells and development dry holes are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are taken into account in depreciation, depletion and amortization.
The Partnership's proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. Under this analysis, the fair value for the Partnership's proved oil and gas properties was estimated using escalated pricing and present value discount factors reflecting risk assessments. Based on this analysis, the Partnership recognized no charges to impairment during 1999, 2000, and 2001.
Oil and Gas Revenues. The Partnership recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Partnership's production entitlement.
Net Income Per Unit. Net income per Unit is computed based on the weighted average number of Units outstanding during the period divided into the net income allocable to the Unitholders. Net income allocable to the Unitholders represents 96.04% of the Partnership's net income.
Financial Instruments. The Partnership's financial instruments consist of cash and cash equivalents, receivables and payables. Management believes the carrying amounts of the financial instruments classified in current assets or liabilities approximate fair value due to their short-term nature.
Derivative Financial Instruments. From time to time, the Partnership has entered into transactions in derivative financial instruments covering future oil and natural gas production principally as a hedge against natural gas price declines. See Note 6--"Hedging Activities" for a discussion of the Partnership's accounting policies related to hedging activities.
Concentration of Credit Risk and Significant Customers. Substantially all of the Partnership's receivables are due from Concorde Gas Marketing, Inc., the marketing subsidiary of Contour Energy E&P, LLC, which purchases approximately 80% of the Partnership's natural gas for resale to a limited number of natural gas transmission companies and other gas purchasers. To date, this concentration has not had a material adverse effect on the financial condition of the Partnership.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications. Certain financial statement items in 1999 and 2000 have been reclassified to conform to the 2001 presentation.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS--(Continued)
NOTE 4--CASH DISTRIBUTIONS
The Partnership maintains a policy of distributing cash that is not required for the conduct of Partnership business to Unitholders on a quarterly basis. During 2001, current year earnings distributions were paid to the managing and special general partners and the unitholders in the amounts of $18,000 and $435,000, or $0.03 per Unit, respectively. However, future distributions to the unitholders and the managing and special general partners are contingent on future operating results.
NOTE 5--RELATED PARTY TRANSACTIONS
The Unitholders have a 96.04% share and the general partners a 3.96% share in the costs and revenues of the Partnership. The Partnership reimburses Contour E&P for all direct costs incurred in managing the Partnership and all indirect costs (principally general and administrative expenses) allocable to the Partnership.
Overhead allocated to the Partnership by Contour E&P for the years ended December 31, 1999, 2000 and 2001 related to general and administrative expenses aggregated $92,000, $62,000 and $44,000, respectively.
Substantially all of the Partnership's gas sales are made to an affiliated company, Concorde Gas Marketing, Inc.("CGM"), an indirect wholly-owned subsidiary of Contour E&P, which remarkets gas to third parties. For 1999, 2000 and 2001, a fee of 2% of the resale price was charged to the Partnership by CGM for its marketing services.
In December 2000, Contour E&P invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for all of the Partnership units not held by Contour E&P. A total of 1,298,724 Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs. After the tender, Contour E&P owned 91.82% of the Units and a 3.94% General Partner interest.
NOTE 6--HEDGING ACTIVITIES
Historically, Contour periodically entered into hedge contracts to protect against commodity price declines on behalf of the Partnership. Because of small production volumes, beginning 2001, the Partnership production no longer was hedged.
Contour periodically uses forward sales contracts, natural gas and crude oil price swap agreements, collars and options to reduce exposure to downward price fluctuations on its natural gas and crude oil production. Contour does not engage in speculative transactions. During 2000, Contour used price swap agreements and collars. Price swap agreements generally provide for Contour to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas and crude oil. Collars combine put and call options to establish a ceiling and a floor. Contour normally employs the average NYMEX price for the last three days of the contract for natural gas and the monthly average of closing NYMEX prices for crude oil as the underlying index ("Index Price"). To the extent the Index Price closes above the established ceiling Contour must make payments to the counterparty on the differential between the Index Price and the ceiling. Conversely, if the Index Price closes below the established floor, the counterparty must make payments to Contour on the differential between the Index Price and the floor. If the Index Price closes between the ceiling and the floor, no settlement is due. Gains and losses realized by the Partnership from hedging activities are included in oil and gas revenues and average sales prices in the period that the related production is sold. Contour's hedging activities also cover the oil and gas production attributable to the interest in such production of the public unitholders in its subsidiary partnerships, including the production of the Partnership, for 1998, 1999 and 2000.
Through natural gas price swap agreements, the Partnership hedged approximately 50% of its natural gas production for 1999 at average NYMEX quoted prices of $2.17/Mmbtu, before transaction and transportation costs. For 2000, the Partnership hedged approximately 72% of its natural gas production using price swap
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS--(Continued)
agreements (48%) and a costless collar (24%). The average price received under the swap agreements was $2.59/Mmbtu. The costless collar included a ceiling of $4.98/Mmbtu and a floor of $4.00/mmbtu at the closing Index Price. As of December 31, 2001, none of the Partnership's anticipated natural gas production for 2002 has been hedged.
Through crude oil price swap agreements, the Partnership hedged approximately 29% of its crude oil production for 1999 at an average NYMEX quoted price of $20.00/Bbl, before transaction and transportation costs. For 2000, the Company hedged approximately 66% of its crude oil production using price swap agreements (41%) and costless collars (25%). The average price received under the swap agreements was $26.21/Bbl. The costless collars included an average ceiling of $32.21/Bbl and an average floor of $26.11/Bbl at the closing Index Price. As of December 31, 2001, none of the Partnership's crude oil production for 2002 had been hedged.
Hedging activities decreased Partnership oil and natural gas revenues by approximately $17,000 and $109,000 in 1999 and 2000, respectively, as compared to estimated revenues had no hedging activities been conducted.
The credit risk exposure from counterparty nonperformance on natural gas forward sales contracts and derivative financial instruments is generally the amount of unrealized gains under the contracts. The Partnership has not experienced counterparty nonperformance on these agreements.
The Partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The Partnership was not party to any derivative instruments during 2001 and as such there was no impact from the adoption of SFAS 133.
NOTE 7--NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued two new pronouncements: Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS 142, effective for fiscal years beginning after December 15, 2001, addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, Intangible Assets. It addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. This Statement also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The Partnership expects no impact on its financial statements from the adoption of these standards.
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.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS--(Continued)
NOTE 8--SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This section provides information required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities."
Capitalized costs. Capitalized costs and accumulated depreciation, depletion and amortization relating to oil and gas producing activities, all of which are conducted within the continental United States, are summarized below.
Costs Incurred. All costs were incurred in oil and gas property development activities (as defined in the Partnership Agreement) and aggregated $14,000, $(23,000) and $18,000 in 1999, 2000 and 2001, respectively.
Reserves. The following table summarizes the Partnership's net ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves, all of which are located in the continental United States, for the years ended December 31, 1999, 2000 and 2001.
Oil and gas proved reserves cannot be measured exactly. Reserve estimates are inherently imprecise and may be expected to change as additional information becomes available. Estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve estimates are based on many factors related to reservoir performance which require evaluation by the engineers interpreting the available data, as well as price and other economic factors. The reliability of these estimates at any point in time depends on the quality and quantity of the technical and economic data, the production performance of the reservoirs as well as extensive engineering judgment. Further, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Consequently, reserve estimates are subject to revision as additional data becomes available during the producing life of a reservoir. There also can be no assurance that the reserves set forth herein will ultimately be produced. In addition, the estimates of future net revenues from proved reserves of the Partnership and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct when judged against actual subsequent experience.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS--(Continued)
Standardized Measure. The following table of the Standardized Measure of Discounted Future Net Cash Flows concerning the standardized measure of future cash flows from proved oil and gas reserves are presented in accordance with Statement of Financial Accounting Standards No. 69. As prescribed by this statement, the amounts shown are based on prices and costs at the end of each period, and with a 10% annual discount factor. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the fields. Accordingly, the estimates of future net revenues from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.
Future cash inflows are computed by applying year-end prices of oil and gas to year-end quantities of proved oil and gas reserves. Future production and development costs are computed by Contour E&P's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Partnership's proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Partnership's oil and gas properties.
The standardized measure of discounted future net cash flows as of December 31, 1999, 2000 and 2001 was calculated using prices in effect as of those dates, which averaged $25.46, $26.45 and $20.79, respectively, per barrel of oil and $2.15, $10.05 and $2.57, respectively, per Mcf of natural gas.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
NOTES TO FINANCIAL STATEMENTS--(Continued)
Changes in Standardized Measure. Changes in standardized measure of future net cash flows relating to proved oil and gas reserves are summarized below.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
None.
PART III
Item 10.
Item 10. Managers of Contour Energy E&P, LLC
General
The Partnership has no directors, officers or employees. Managers of Contour E&P perform all management functions for the Partnership. Contour E&P had 47 employees as of December 31, 2001, and its staff includes employees experienced in geology, geophysics, petroleum engineering, land acquisition and management, finance, accounting, and administration.
Background of Contour Energy E&P, LLC
Contour Energy E&P, LLC (formerly Kelley Oil Corporation) is an oil and gas operating company formed in April 1983. Since January 1986, Contour E&P has been engaged in the management of the DDPs. Since the Consolidation in February 1995, Contour E&P has been a wholly-owned subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas Corporation).
Managers of Contour Energy E&P, LLC.
Set forth below are the names, ages and positions of the managers of Contour E&P. [All managers hold office until their successors are duly appointed and qualified.]
Rick G. Lester was appointed a manager of Contour Energy E&P, LLC upon it formation in 2001. Prior to that he served Executive Vice President and Chief Financial Officer and a director of Kelley Oil Corporation, the predecessor Company to Contour Energy E&P, LLC. Previously, he was Vice President and Chief Financial Officer of Domain Energy Corporation.
Kenneth R. Sanders was appointed a manager of Contour Energy E&P, LLC upon it formation in 2001. Prior to that he served as President, CEO and director of Kelley Oil Corporation, the predecessor Company to Contour Energy E&P, LLC. Previously, he was Vice-President--Exploitation, Acquisitions & Engineering of Seagull Energy E&P, Inc.
Beneficial Ownership Reporting
Not applicable.
Item 11.
Item 11. Executive Compensation
Not applicable. See "Certain Relationships and Related Transactions."
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Beneficial Owners
The following table sets forth information as of December 31, 2001 with respect to the only Unitholder known by the Partnership to own beneficially more than five percent of the Partnership's Units.
Management
The following table sets forth information as of December 31, 2001 with respect to Units beneficially owned, directly or indirectly, by each of the managers of Contour E&P and by all managers of Contour E&P as a group.
- -------- (1)Represents direct beneficial ownership.
Item 13.
Item 13. Certain Relationships and Related Transactions
The Unitholders have a 96.04% share and the General Partners a 3.96% share in the costs and revenues of the Partnership. Allocations of costs and revenues to Unitholders are made in accordance with the number of Units owned. The General Partners contributed $1,983,258 to the Partnership for their 3.96% interest in the same proportion as the deferred subscriptions for Units were payable.
Contour E&P is reimbursed for its direct costs and an allocable portion of its general and administrative expenses incurred as Managing General Partner. See Note 5 in the Notes to Financial Statements.
It is the policy of the Partnership to engage in transactions with related parties only on terms that are no less favorable to the Partnership than could be obtained on an arm's-length basis from unrelated parties. The Partnership believes that all payments to related parties are reasonable and in amounts not greater than fees that would be charged on an arm's-length basis by unrelated parties.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)Financial Statements and Schedules:
(1) Financial Statements: The financial statements required to be filed are included under Item 8 of this Report.
(2) Schedules: Schedules for which provision is made in applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.
(3) Exhibits:
(b)Reports on Form 8-K:
No reports on Form 8-K were filed by the Registrant during the fourth quarter of 2001.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, this 16th day of April 2002.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
By: CONTOUR ENERGY E&P, LLC, Managing General Partner
/s/ Kenneth R. Sanders /s/ Rick G. Lester By:_________________________ By: _________________________________ Kenneth R. Sanders Rick G. Lester Manager
Manager Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 16th day of April 2002 by the following persons in their capacity as managers of the Registrant's managing general partner.
/s/ Kenneth R. Sanders /s/ Rick G. Lester __________________________ ________________________ Kenneth R. Sanders Rick G. Lester