ITEM 3. LEGAL PROCEEDINGS
KOGC is involved from time to time 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 Kelley Oil 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, and transfer of the Units is substantially restricted by the provisions of the Partnership Agreement. As of February 28, 1997, there were 658 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.
DISTRIBUTIONS ------------- ---- First quarter................................. $ .04 Second quarter................................ .09 Third quarter................................. .10 Fourth quarter................................ .10
---- First quarter................................. .12 Second quarter................................ .18 Third quarter................................. .18 Fourth quarter................................ .21
---- First quarter................................. .22
The distribution for each quarter in which payments were made represents substantially all of the Partnership's net available cash from the preceding quarter's operations. 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.
In addition to its regular distributions of net available cash from quarterly operations, the Partnership distributed $340,105 of uncommitted capital or $0.20 per Unit to the Public Unitholders in March 1996. As of March 15, 1997, the Contemplated Capital for the remainder of the drilling activities projected for the Partnership will exceed the Committed Expenditures by approximately $2.7 million, or $0.12 per Unit. Accordingly, a distribution of the excess Contemplated Capital is expected to be made in 1997. 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 should be read in conjunction with those Financial Statements and the related Notes thereto.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
- ------------ (1) Per Unit amounts are based on the Unitholders' 96.04% share of net income (loss).
(2) The Partnership's net available cash generally corresponds to the sum of its net income (loss) plus exploration and dry hole costs and noncash charges for impairment of oil and gas properties and depreciation, depletion and amortization.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
PROPERTY IMPAIRMENT UNDER FAS 121. In the fourth quarter of 1995, the Partnership implemented the Financial Accounting Standards Board's Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for LongLived Assets to be Disposed Of ("FAS 121"). Under FAS 121, certain assets are required to be reviewed periodically for impairment whenever circumstances indicate their carrying amount exceeds their fair value and may not be recoverable. The Partnership performed an assessment of the carrying value of its oil and gas properties indicating an impairment should be recognized at year end. Under this analysis, the fair value of the Partnership's oil and gas properties was estimated on a depletable unit basis using escalated pricing and present value discount factors reflecting risk assessments. Based on this
analysis, the Partnership recognized a noncash impairment charge of $10.9 million against the carrying value of its oil and gas properties under FAS 121 at December 31, 1995.
HEDGING ACTIVITIES. Kelley periodically has used forward sales contracts, natural gas swap agreements and options to reduce exposure to downward price fluctuations on its natural gas production. The swap agreements generally provide for Kelley to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas. Gains and losses realized by Kelley from hedging activities are included in oil and gas revenues and average sales prices. Kelley's hedging activities also cover the oil and gas production attributable to the interest in such production of the public unitholders in Kelley's subsidiary partnerships. Through a combination of natural gas swap agreements, forward sales contracts and options, approximately 55% of Kelley's natural gas production for 1996 was affected by Kelley's hedging transactions at an average NYMEX quoted price of $2.25 per MMBtu before transaction and transportation costs. Approximately 44% of Kelley's anticipated natural gas production for the first eight months of 1997 has been hedged by natural gas swap agreements at an average NYMEX quoted price of $2.42 per MMBtu before transaction and transportation costs. Hedging activities related to swaps and options reduced revenues by approximately $3.1 million in 1996 and increased revenues by approximately $1.8 million in 1995 as compared to estimated revenues had no hedging activities been conducted. Hedging activities were not material in 1994. At December 31, 1996, the Company had an unrealized loss of $2.6 million.
RESULTS OF OPERATIONS
GENERAL. The Partnership commenced operations in the first quarter of 1994. Accordingly, the Partnership's operating results for 1994 do not reflect a full year of production, and comparisons with 1995 and 1996 operating data may not be meaningful.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995. Oil and gas revenues of $18,986,000 in 1996 increased 145.8% compared to $7,723,000 in 1995. Production of natural gas increased 96.8% to 7,872,000 Mcf in 1996 from 4,000,000 Mcf in 1995, while the average price of natural gas increased 32.2% to $2.27 per Mcf in 1996 from $1.71 per Mcf in 1995. Production of crude oil in 1996 totaled 49,168 barrels, with an average sales price of $21.59 per barrel, compared to 49,816 barrels at $16.58 per barrel in the prior year, representing a volume decrease of 1.3% and a price increase of 30.2%. The increase in revenues and production from 1995 levels reflects the Partnership's completion of 38 wells during 1996.
Lease operating expenses and severance taxes were $2,348,000 in 1996 and $1,123,000 in 1995, an increase of 109.1%, reflecting higher production levels. On a unit of production basis, these expenses increased to $0.29 per Mcfe in 1996 from $0.26 per Mcfe in 1995.
The Partnership expensed exploration and dry hole costs of $606,000 in 1996 and $6,767,000 in 1995, a decrease of 91.0%, primarily reflecting a larger allocation of resources to exploratory prospects in south Louisiana during 1995.
General and administrative expenses of $854,000 in 1996 increased 37.9% from $620,000 in 1995, reflecting an increase in the Partnership's share of administration costs associated with development operations of Kelley. On a unit of production basis, these expenses decreased to $0.10 per Mcfe 1996 from $0.14 per Mcfe in 1995.
Depreciation, depletion and amortization ("DD&A") decreased to $5,536,000 in 1996 compared to $6,617,000 in 1995 due to lower depletion rates following noncash impairment charges aggregating $10,914,000 recognized in the fourth quarter of 1995 against the carrying value of the Partnership's oil and gas properties under FAS 121. On a unit of production basis, DD&A decreased to $0.68 per Mcfe in 1996 from $1.54 per Mcfe in 1995. See "General-Property Impairment under FAS 121" above.
The Partnership realized net income in 1996 of $10,896,000 or $0.50 per Unit compared to a net loss of $15,394,000 or $0.71 per Unit in 1995, reflecting the foregoing developments. Net available cash from Partnership operations, representing its net income or loss plus exploration and dry hole costs and noncash charges for DD&A and the
1995 property impariment, increased 91.4% in 1996 to $17,038,000 or $0.78 per Unit compared to $8,904,000 or $0.41 per Unit in 1995.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994. Oil and gas revenues of $7,723,000 in 1995 increased 847.6% compared to $815,000 in 1994. During 1995, production of natural gas increased 1,079.9% from 339,000 Mcf in 1994 to 4,000,000 Mcf, while the average price of natural gas increased less than 1% from $1.70 per Mcf in 1994 to $1.71 per Mcf in 1995. Production of crude oil in 1995 totaled 49,816 barrels, with an average sales price of $16.58 per barrel compared to 14,804 barrels at $16.17 per barrel in 1994, representing production and price increases of 236.5% and 2.5%, respectively. The increase in revenues and production from 1994 levels reflects the Partnership's completion of 27 wells brought on line during 1995. In addition, while natural gas prices have remained depressed, hedging activities contributed $429,000 to oil and gas revenues in 1995.
Lease operating expenses and severance taxes were $1,123,000 in 1995 versus $126,000 in 1994, an increase of 791.3%, reflecting the increased level of production. On a unit of production basis, these expenses decreased to $0.26 per Mcfe in 1995 from $0.29 per Mcfe in 1994, due primarily to a decrease in the severance tax rate during the last half of 1995.
The Partnership expensed exploration and dry hole costs of $6,767,000 in 1995 and $3,389,000 in 1994, an increase of 99.7%, primarily reflecting a larger allocation of resources to exploratory prospects in south Louisiana during 1995. Most of the Partnership's drilling expenditures in 1994 were incurred for development wells and were therefore capitalized.
General and administrative expenses of $620,000 in 1995 increased 596.6% from $89,000 in 1994, reflecting the Partnership's share of administration costs associated with development operations of the Partnership and other partnerships managed by Kelley Oil. On a unit of production basis, these expenses decreased to $0.14 per Mcfe in 1995 from $0.21 per Mcfe in 1994, reflecting costs savings from a significant staff reduction by Kelley Oil at the end of 1994.
DD&A increased 309.0% from $1,618,000 in 1994 to $6,617,000 in 1995 as a result of significantly higher depletion rates due to increased production and reserves over the prior year. On a unit of production basis, these noncash charges decreased to $1.54 per Mcfe in 1995 from $3.78 per Mcfe in 1994. The Partnership recognized an additional noncash charge of $10,914,000 as of December 31, 1995 for impairment of the carrying value of its oil and gas properties under FAS 121. See "General-Property Impairment under FAS 121" above.
The Partnership recognized a net loss of $15,394,000 or $0.71 per Unit in 1995 compared to a net loss of $4,099,000 or $0.19 per Unit in 1994, reflecting the foregoing developments. Net available cash from Partnership operations, representing its net loss plus exploration and dry hole costs and noncash charges for DD&A and the 1995 property impairment, aggregated $8,904,000 or $0.41 per Unit in 1995 compared to $908,000 or $0.04 per Unit in 1994.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY. Net cash provided by the Partnership's operating activities during 1996, as reflected on its statements of cash flows, totaled $8,121,000. The Partnership's cash position was increased during 1996 by payments of subscriptions for Units and General Partner contributions aggregating $22,920,000. During the year, funds were used in investing and financing activities comprised primarily of property and equipment expenditures of $12,601,000 for development of the Partnership's oil and gas properties and distributions to partners aggregating $19,334,000. As a result of these activities, the Partnership's cash and cash equivalents decreased from $57,000 at December 31, 1995 to $25,000 at December 31, 1996.
CAPITAL RESOURCES. The Partnership Agreement contemplates pro rata contributions from the Unitholders and the General Partners of $62,593,242 (96.04%) and $2,580,897 (3.96%), respectively, or an aggregate of $65,174,139 ("Contemplated Capital"). Under the deferred payment option applicable to investments in the Partnership exceeding $10,000, deferred subscriptions for Units and the General Partners' deferred contributions were payable when called by Kelley Oil during the period ended November 30, 1994. Kelley Oil initially subscribed for 18,821,655 Units in addition to its 3.94% General Partner interest in the Partnership. Following defaults by Public Unitholders on a total of 342,234
Units, the defaulted Units were subscribed by Kelley Oil in accordance with its undertaking in the Partnership Agreement. This increased Kelley Oil's total subscription commitment to $60,059,529 or 92.15% of the Partnership's total Contemplated Capital (the "KOIL Share"), with the Public Unitholders committing for the balance or 7.85% of the total Contemplated Capital (the "Public Share").
The Partnership Agreement requires any contributions of the partners not used or committed to be used for drilling activities during the two-year Commitment Period ended February 29, 1996, except for necessary operating capital, to be distributed to the partners on a pro rata basis as a return of capital. For this purpose, "committed for use" means funds that have been contracted or allocated by Kelley Oil for drilling, completion or other Partnership activities, and "necessary operating capital" means funds that, in the opinion of Kelley Oil, should remain in reserve to assure the continued operation of the Partnership.
From its inception through December 31, 1995, a total of $43.7 million was expended on Partnership activities, including syndication costs. At the end of the Commitment Period in February 1996, a total of $15.5 million was contracted or allocated for drilling an additional 34 wells during 1996 and 14 proved undeveloped locations thereafter, plus $1.5 million for drilling overruns, contingencies and necessary operating capital. The expenditures through 1995 plus these budgeted expenditures aggregated $60.7 million ("Committed Expenditures"). On February 29, 1996, the Contemplated Capital exceeded the Committed Expenditures by $4.4 million or $0.20 per Unit. Accordingly, the Public Share of the excess Contemplated Capital aggregating $340,105 was distributed to the Public Unitholders as a return of capital in March 1996.
During 1996, Kelley initiated a program for streamlining operations, improving drilling efficiency and reducing lease operating costs. These efforts generated cost savings that have effectively reduced the February 1996 estimate for Committed Expenditures. From inception through December 31, 1996, a total of $55.3 million was expended on Partnership activities, including syndication costs. For the balance of the Partnership's drilling program, a total of $2.4 million has been contracted or allocated for drilling an additional seven wells during 1997 and two proved undeveloped locations thereafter, plus $0.3 million for drilling overruns, contingencies and necessary operating capital. The expenditures through 1996 plus these budgeted expenditures aggregate $58.0 million, representing a total reduction of $2.7 million or $.12 per Unit in Committed Expenditures (the "Commitment Reduction"). As a result of the Commitment Reduction, a distribution of the excess Contemplated Capital is expected to be made in 1997.
As of March 15, 1997, Kelley Oil had contributed $54.6 million to the Partnership, together with interest at a market rate on the portion of its commitment that remained outstanding after November 1994. After giving effect to the February 1996 reduction in Contemplated Capital under the Partnership Agreement and the additional Commitment Reduction in 1997, the KOIL Share of Committed Expenditures will be reduced to $53.4 million, entitling Kelley Oil to participate in the planned 1997 distribution of excess Contemplated Capital resulting from the Commitment Reduction. Kelley Oil's return of capital will be limited to its excess contribution aggregating $1.2 million or $.06 per Unit.
In December 1996, KOGC entered into a $125 million revolving credit facility with a group of banks (the "Credit Facility"). The agreement for the Credit Facility requires the payment of interest only until December 2000, when all borrowings will be repayable. The Partnership and Joint Venture are guarantors under the Credit Facility. The Credit Facility is secured by all the oil and gas properties and other assets of KOGC and its subsidiaries, including the Partnership and the Joint Venture. The agreement covering the Credit Facility provides various financial covenants as well as restrictions on additional debt, mergers and asset sales, but limits the lenders' recourse upon any default to Partnership and Joint Venture assets attributable to Kelley Oil's interests in the Partnership.
DISTRIBUTION POLICY. The Partnership maintains a policy of distributing the maximum amount of its net available cash to Unitholders on a quarterly basis. For these purposes, net available cash is generally defined as the net operating cash flow of the Partnership after deducting working capital requirements. The Partnership made four quarterly distributions in 1996 aggregating $0.69 per Unit or a total of $14,396,000, together with $594,000 to the General Partners for their general partner interests. In March 1997, the Partnership made a quarterly distribution of $0.22 per Unit (aggregating $4,590,000), together with $189,000 to the General Partners for their general partner interests. The distributions in each quarter generally represented substantially all of the Partnership's net available cash from prior quarter operations. The Partnership intends to continue making quarterly distributions consistent with its cash distribution policy.
Net available cash per Unit from operations in the quarter and year ended December 31, 1996 was determined as follows:
QUARTER YEAR ENDED ENDED DECEMBER 31, DECEMBER 31, 1996 1996 -------- ------
Net income per Unit........................... $ .19 $ .50 Exploration and dry hole costs per Unit....... -- .03 Depreciation, depletion and amortization charges per Unit............... .03 .25 -------- ------- Net available cash per Unit................. $ .22 $ .78 ======== =======
INFLATION AND CHANGING PRICES. Oil and natural gas prices 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 gas prices received by Kelley Partners during the periods indicated.
AVERAGE AVERAGE OIL PRICE GAS PRICE ($/BBL) ($/MCF) YEAR ENDED: --------- --------- December 31, 1994............................... $ 16.17 1.70 December 31, 1995............................... 16.58 1.71 December 31, 1996............................... 21.59 2.27
FORWARD-LOOKING STATEMENTS
FROM TIME TO TIME, THE PARTNERSHIP MAY PUBLISH 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, RESERVE ESTIMATES, RATES AND TIMING OF FUTURE PRODUCTION OF OIL AND GAS, AND CHANGES IN THE LEVEL AND TIMING OF FUTURE COSTS AND EXPENSES RELATED TO DRILLING AND OPERATING ACTIVITIES.
WORDS SUCH AS "ANTICIPATED," "EXPERT," "ESTIMATE," "PROJECT" AND SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS. FORWARD-LOOKING STATEMENTS MAY BE MADE IN MANAGEMENT'S STATEMENTS (ORALLY OR IN WRITING) INCLUDING PRESS RELEASES, AND IN FILINGS OF THE SEC, INCLUDING THIS REPORT.
In addition to "Uncertainties in Estimating Reserves" and other factors mentioned in this Report, the following additional risk factors should be considered:
DEPLETION OF RESERVES. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The Partnership's business plan does not contemplate developing or acquiring additional reserves.
VOLATILITY OF OIL, NATURAL GAS AND NATURAL GAS LIQUIDS PRICES. The Partnership's financial results are affected significantly by the prices received for its oil, natural gas and natural gas liquids production. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and are expected to continue to be volatile in the future. The prices received by the Partnership for its oil, natural gas and natural gas liquids production and the levels of production are subject to government regulation, legislation and policies. The Partnership's future financial condition and results of operations will depend, in part, upon the prices received for its oil and natural gas production, as well as the costs of producing its reserves.
OPERATING HAZARDS AND UNINSURED RISKS. The Partnership's oil and natural gas business also is subject to all of the operating risks associated with the production of oil and natural gas, including uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater and shoreline contamination), cratering, mechanical difficulties, fires, explosions, pollution and other risks, any of which could result in substantial losses. Although the Partnership maintains insurance at levels that it believes are consistent with industry practices, it is not fully insured against all risks. Losses and liabilities arising from uninsured and underinsured events could have a material adverse effect on the financial condition and operations of the Partnership.
The availability of a ready market for the Partnership's oil and natural gas production also depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. Natural gas wells may be shut in for lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM:
INDEPENDENT AUDITORS' REPORT
To the Partners of Kelley Partners 1994 Development Drilling Program
We have audited the accompanying balance sheets of Kelley Partners 1994 Development Drilling Program (a Texas limited partnership) as of December 31, 1996 and 1995, and the related statements of operations, cash flows, and changes in partners' equity for each of the two years in the period ended December 31, 1996. These financial statements are the responsibility of management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits 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 1994 Development Drilling Program at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
As discussed in Note 1, in 1995 the Partnership changed its method of accounting for the impairment of long-lived assets to conform with Statement of Financial Accounting Standards No. 121.
DELOITTE & TOUCHE LLP
Houston, Texas March 3, 1997
REPORT OF INDEPENDENT AUDITORS
To the Partners of Kelley Partners 1994 Development Drilling Program
We have audited the balance sheet of Kelley Partners 1994 Development Drilling Program (a Texas limited partnership) as of December 31, 1994, and the related statements of operations, partners' equity, and cash flows for the period from February 28, 1994 (date of inception) through December 31, 1994. The balance sheet as of December 31, 1994 is not presented separately herein. These financial statements are the responsibility of management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audit in accordance with generally accepted auditing standards. 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kelley Partners 1994 Development Drilling Program at December 31, 1994 and results of its operations and its cash flows for the period from February 28, 1994 (date of inception) through December 31, 1994, in conformity with generally accepted accounting principles.
Ernst & Young LLP
Houston, Texas March 6, 1995
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM BALANCE SHEETS
($ IN THOUSANDS)
See Notes to Financial Statements.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF OPERATIONS
(IN THOUSANDS EXCEPT PER UNIT DATA)
See Notes to Financial Statements.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
See Notes to Financial Statements.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CHANGES IN PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996 AND THE PERIOD FROM FEBRUARY 28, 1994 (DATE OF INCEPTION) THROUGH DECEMBER 31, 1994
(IN THOUSANDS)
See Notes to Financial Statements.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. Kelley Partners 1994 Development Drilling Program, a Texas limited partnership (the "Partnership"), commenced operations on February 28, 1994 upon completion of a public offering of 20,864,414 units of limited partner interests and general partner interests (the "Units") in the Partnership at $3.00 per Unit. Subscribers for more than 3,333 Units were entitled to defer up to 90% of their subscriptions, with deferred subscriptions payable when called through November 30, 1994. As of December 31, 1996, Unit subscriptions aggregating $58,420,000 were paid, and subscriptions receivable were outstanding, aggregating $5,819,000, all of which was receivable from Kelley Oil Corporation, the managing general partner of the Partnership ("Kelley Oil"). In addition, as of December 31, 1996, Kelley Oil had contributed $2,397,000 to the Partnership for its 3.94% general partner interest, and David L. Kelley, special general partner of the Partnership, had contributed $12,166 for his .02% general partner interest.
The Partnership was formed for the sole purpose of financing the drilling of development wells, as defined in its partnership agreement (the "Partnership Agreement"), on selected properties owned by Kelley Operating Company, Ltd. ("Kelley Operating"), a Texas limited partnership of which Kelley Oil & Gas Partners, Ltd. ("Kelley Partners") was the sole limited partner. The Partnership's development activities have been conducted through a joint venture (the "Joint Venture") between the Partnership and Kelley Operating, which has retained a 20% interest in the Joint Venture after Payout (as defined in the Joint Venture Agreement) in consideration of its contribution of drilling rights. In February 1995, the equity interests in Kelley Partners and Kelley Oil were consolidated (the "Consolidation") in Kelley Oil & Gas Corporation (collectively with its predecessors, "KOGC"). In March 1996, Kelley Partners was merged into KOGC, and Kelley Partners' 98% limited partner interest in Kelley Operating was transferred to Kelley Oil.
As of December 31, 1996, Kelley Oil and its officers and directors owned 19,163,889 (91.9%) Units and 1,000 (.01%) Units, respectively. The Partnership has no officers, directors or employees. The officers and employees of Kelley Oil perform the management and administrative functions of the Partnership. The Partnership reimburses Kelley Oil for all direct costs incurred in managing the Partnership and all indirect costs allocable to the Partnership, principally comprised of general and administrative expenses.
Kelley Oil contributed $38,824,016 or 64.6% of its total subscription commitment during the two-year period ended February 29, 1996 (the "Commitment Period"), together with interest at a market rate on the portion of its subscription commitment that remained outstanding after November 30, 1994. As of February 29, 1996, approximately $60.7 million or 93.2% of the Partnership's committed capital had been used or committed to drilling activities, including syndication costs. The Partnership Agreement requires any contributions of the partners not used or committed to be used for the drilling of development wells during the Commitment Period, except for necessary operating capital, to be distributed to the partners on a pro rata basis as a return of capital. In accordance with this requirement, the Partnership distributed $340,105 of uncommitted capital or $0.20 per Unit to the Unitholders other than Kelley Oil (the "Public Unitholders") in March 1996, and Kelley Oil's unfunded subscription commitment was reduced proportionately to $17.2 million as of the date of the distribution. Future drilling activities were limited to prospects being drilled or committed for drilling as of the end of the Commitment Period.
During 1996, KOGC and its subsidiaries (collectively, "Kelley") initiated a program for streamlining operations, improving drilling efficiency and reducing lease operating costs. These efforts generated cost savings that reduced the Partnership's prior estimate for total expenditures from $60.7 million to $58 million, representing a reduction of $2.7 million or $.12 per Unit (the "Commitment Reduction"). As a result of the Commitment Reduction, a distribution of the excess Contemplated Capital is expected to be made in 1997.
As of March 15, 1997, Kelley Oil had contributed $54.6 million to the Partnership, together with interest at a market rate on the portion of its commitment that remained outstanding after November 1994. After giving effect to the February 1996 reduction in committed capital under the Partnership Agreement and the additional Commitment Reduction
in 1997, the Kelley Oil's share of the Partnership's total expenditures will be reduced to $53.4 million, entitling Kelley Oil to participate in the planned 1997 distribution of additional uncommitted capital resulting from the Commitment Reduction. Kelley Oil's return of capital will be limited to its excess contribution aggregating $1.2 million or $.06 per Unit.
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.
OIL AND GAS PROPERTIES. Oil and gas properties are located in the United States, and are held of record by Kelley Operating. 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. Cost centers for amortization purposes are determined on a field-by-field basis. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are taken into account in depreciation, depletion and amortization.
The successful efforts method imposes limitations on the carrying or book value of oil and gas properties and requires an impairment provision or noncash charge against earnings for any quarter in which the carrying value of oil and gas properties exceeds the standardized measure of undiscounted future net cash flows from its proved oil and gas reserves based on prices received for its oil and gas production as of the end of that quarter or a subsequent date prior to publication of financial results for the quarter.
PROPERTY IMPAIRMENT UNDER FAS 121. In the fourth quarter of 1995, the Partnership implemented the Financial Accounting Standards Board's Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for LongLived Assets to be Disposed Of ("FAS 121"). Under FAS 121, certain assets are required to be reviewed periodically for impairment whenever circumstances indicate their carrying amount exceeds their fair value and may not be recoverable. The Partnership performed an assessment of the carrying value of its oil and gas properties indicating an impairment should be recognized at year end. Under this analysis, the fair value of the Partnership's oil and gas properties was estimated on a depletable unit basis using escalated pricing and present value discount factors reflecting risk assessments. Based on this analysis, the Partnership recognized a noncash impairment charge of $10.9 million against the carrying value of its oil and gas properties under FAS 121 at December 31, 1996.
SYNDICATION AND ORGANIZATION COSTS. Costs and expenses incurred in connection with the syndication and organization of the Partnership aggregating approximately $1,571,000 have been charged to partners' equity. These syndication costs include approximately $750,000 of general and administrative expenses allocated by Kelley Oil for expenses directly identified with syndication and organization activities.
NET INCOME (LOSS) PER UNIT. Net income (loss) per Unit is computed based on the weighted average number of Units outstanding during the period divided into the net income (loss) allocable to the Unitholders.
FINANCIAL INSTRUMENTS. The Partnership's financial instruments consist of cash and cash equivalents, receivables, and payables.
DERIVATIVE FINANCIAL INSTRUMENTS. From time to time, the Partnership has entered into transactions in derivative financial instruments covering future natural gas production principally as a hedge against natural gas price declines. Realized and unrealized gains and losses are recorded in other assets or liabilities until the underlying natural gas is produced and sold, at which time those gains and losses are included in oil and gas revenues. See Note 5 - Hedging Activities.
CONCENTRATION OF CREDIT RISK. Substantially all of the Partnership's receivables are due from the marketing subsidiary of Kelley Oil, which purchases natural gas for resale to a limited number of natural gas transmission companies and other gas purchasers. See Note 3 - Related Party Transactions.
RISKS AND UNCERTAINTIES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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.
NOTE 2 - CASH DISTRIBUTIONS
In addition to the March 1996 distribution of the Public Unitholders' pro rata share of uncommitted capital and the planned 1997 distribution of additional uncommitted capital described in Note 1 above, the Partnership has paid quarterly cash distributions reflected in the following table. The distribution in each quarter was based upon net available cash generated from operations in the preceding quarter.
---- First quarter..................... $.04 Second quarter.................... .09 Third quarter..................... .10 Fourth quarter.................... .10 ---- Total........................... $.33 ====
---- First quarter..................... $.12 Second quarter.................... .18 Third quarter..................... .18 Fourth quarter.................... .21 ---- Total........................... $.69 ====
NOTE 3 - 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 Kelley Oil for all direct costs incurred in managing the Partnership and all indirect costs (principally general and administrative expenses) allocable to the Partnership.
For the period from inception through December 31, 1994 and the years ended December 31, 1995 and 1996, Kelley Oil was reimbursed by the Partnership for costs directly associated with acquisition, exploration and development activities aggregating $2,496,000, $2,649,000 and $1,245,000, respectively, and for its allocable portion of general and administrative expenses aggregating $52,000, $542,000 and $753,000, respectively. For the period ended December 31, 1994 and the years ended December 31, 1995 and 1996, the Partnership capitalized $1,592,000, $1,963,000 and $611,000, respectively, of allocated direct costs to oil and gas properties.
Kelley Partners advanced approximately $1,879,000 on behalf of the Partnership prior to the closing of the Partnership's offering of Units for the purpose of funding drilling activities. The entire amount of these advances, together with interest at a market rate, was repaid following the closing of the Partnership's offering.
KOGC maintains a $125 million revolving credit facility with a group of bankers (the "Credit Facility"). The Partnership, the Joint Venture and KOGC's other subsidiary partnerships are guarantors. The Credit Facility is secured by all the oil and gas properties and other assets of the borrowers and the guarantors, including the Partnership and the Joint Venture. The agreement covering the Credit Facility provides various financial covenants as well as restrictions on additional
debt, mergers and asset sales, but limits the lenders' recourse upon any default to Partnership and Joint Venture assets attributable to Kelley Oil's interests in the Partnership.
Substantially all of the Partnership's gas sales are made to an affiliated company, Concorde Gas Marketing, Inc., an indirect wholly owned subsidiary of Kelley Oil ("CGM"), which remarkets gas to third parties. During 1994, CGM received for its services either fees or a marketing differential equal to $0.05 per MMBtu of gas sold and delivered. For 1995, the fee was modified to 2% of the resale price for marketed natural gas.
NOTE 4 - SALES TO MAJOR CUSTOMERS
Sales to customers in excess of 10% of total oil and gas sales for the period from inception through December 31, 1994 and the years ended December 31, 1995 and 1996 were as follows:
(IN THOUSANDS)
FEBRUARY 28, 1994 (DATE OF INCEPTION) THROUGH YEAR ENDED DECEMBER 31, DECEMBER 31, ----------------------- 1994 1995 1996 ------- ----- ----- Concorde Gas Marketing(1)............. 563 6,891 17,186 Falco S & D Inc....................... 233 805 389 - ------------ (1) During 1996, approximately 52% of CGM's gas purchases were made for resale to Sonat Marketing Company (28%), Coral Energy Resources (20%) and LIG Chemical Company (10%). During 1995, approximately 82% of CGM's resales were made to Sonat Marketing Company (22%), Associataed Natural Gas, Inc. (21%), Pontchartrain Natural Gas System (17%), Transok Gas Company (12%) and LIG Chemical Company (10%). During 1994, approximately 73% of GCM's resales were made to Pontchartrain Natural Gas System (23%), LIG Chemical Company (22%), Associated Natural Gas, Inc. (18%) and Fina Natural Gas Company (10%).
NOTE 5 - HEDGING ACTIVITIES
Kelley periodically has used forward sales contracts, natural gas swap agreements and options to reduce exposure to downward price fluctuations on its natural gas production. The swap agreements generally provide for Kelley to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas. Gains and losses realized by Kelley from hedging activities are included in oil and gas revenues and average sales prices. Kelley's hedging activities also cover the oil and gas production attributable to the interest in such production of the public unitholders in Kelley's subsidiary partnerships. Through a combination of natural gas swap agreements, forward sales contracts and options, approximately 55% of Kelley's natural gas production for 1996 was affected by Kelley's hedging transactions at an average NYMEX quoted price of $2.25 per MMBtu before transaction and transportation costs. Approximately 44% of Kelley's anticipated natural gas production for the first eight months of 1997 has been hedged by natural gas swap agreements at an average NYMEX quoted price of $2.42 per MMBtu before transaction and transportation costs. Hedging activities related to swaps and options reduced revenues by approximately $3.1 million in 1996 and increased revenues by approximately $1.8 million in 1995 as compared to estimated revenues had no hedging activities been conducted. Hedging activities were not material in 1994. At December 31, 1996, the Company had an unrealized loss of $2.6 million.
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 and does not anticipate any in future periods.
NOTE 6 - 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.
(IN THOUSANDS)
COSTS INCURRED. All costs were incurred in oil and gas property development activities (as defined in the Partnership Agreement) and aggregated $19,129,000 for the period from inception through December 31, 1994 and $22,959,000 and $13,235,087 for the years ended December 31, 1995 and 1996, 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 period from inception through December 31, 1994 and the years ended December 31, 1995 and 1996. Reserves reflected in the table at February 28, 1994 represent proved undeveloped reserves associated with drilling rights assigned to the Partnership upon formation.
The reported revisions of previous reserve estimates during 1995 reflect downward year-end revisions primarily on undeveloped locations in south Louisiana based on reprocessed 3-D seismic data and a change in the Partnership's drilling strategy to focus exclusively on lower risk north Louisiana locations for the balance of its drilling program. As a result of these factors, the Partnership performed an assessment of the carrying value of its oil and gas properties under
FAS 121 indicating an impairment should be recognized as of year end. See Note 1 - - Summary of Significant Accounting Policies. Based on this analysis, the Partnership recognized a noncash impairment charge of $10.9 million against the carrying values of its oil and gas properties under FAS 121 at December 31, 1995.
STANDARDIZED MEASURE. The table of the Standardized Measure of Discounted Future Net Cash Flows relating to the Partnership's ownership interests in proved oil and gas reserves as of December 31, 1994, 1995 and 1996 is shown below.
(IN THOUSANDS)
DECEMBER 31, -------------------------------- 1994 1995 1996 ------- -------- -------
Future cash inflows......................... $93,218 122,415 129,261 Future production costs..................... (15,227) (16,301) (11,520) Future development costs.................... (16,241) (14,955) (3,063) ------- ------- ------- Future net cash flows..................... 61,750 91,159 114,678 10% annual discount for estimating timing of cash flows...................... (26,194) (35,047) (39,540) ------- ------- ------- Standardized measure of discounted future net cash flows................... $35,556 56,112 75,138 ======= ======= =======
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 Kelley Oil'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, 1994, 1995 and 1996 was calculated using prices in effect as of those dates, which had a weighted average of $15.65, $19.73 and $24.93, respectively, per barrel of oil and $1.71, $2.03 and $3.66, respectively, per Mcf of natural gas.
CHANGES IN STANDARDIZED MEASURE. Changes in standardized measure of future net cash flows relating to proved oil and gas reserves are summarized below.
(IN THOUSANDS)
Sales of oil and gas, net of production costs, are based on historical results. Extensions and discoveries, the changes due to revisions in standardized variables and the accretion of discount are reported on a discounted basis.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
In connection with the Contour Transaction, the Partnership dismissed Ernst & Young LLP ("E&Y") as its principal accountant, effective February 15, 1996. On the same date, the Partnership engaged Deloitte & Touche LLP ("D&T") as its principal accountant to audit its financial statements. The change in accountants was approved by the audit committee of the board of directors of Kelley Oil, contingent upon the closing under the Purchase Agreement. E&Y's report on the Partnership's financial statements for the period from inception on February 28, 1994 through December 31, 1994 did not contain an adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principles. During the last two years and the interim period prior to the date of the change in accountants, (i) the Partnership had no disagreements with E&Y on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, (ii) E&Y did not advise the Partnership of any "reportable event" as defined in Regulation S-K under the Securities Exchange Act of 1934 and (iii) the Partnership did not consult with D&T on any accounting, auditing, financial reporting or any other matters.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF KELLEY OIL CORPORATION
GENERAL
The Partnership has no directors, officers or employees. Directors and officers of Kelley Oil perform all management functions for the Partnership. Kelley Oil had 70 employees as of January 1, 1997, and its staff includes employees experienced in geology, geophysics, petroleum engineering, land acquisition and management, finance, accounting and administration.
BACKGROUND OF KELLEY OIL
Kelley Oil is an independent oil and gas company formed in April 1983. Since January 1986, Kelley Oil has been engaged in the management of the DDPs. Since the Consolidation in February 1995, Kelley Oil has been a wholly owned subsidiary of KOGC.
EXECUTIVE OFFICERS OF KELLEY OIL
Set forth below are the names, ages and positions of the current executive officers and directors of the Company. All directors are elected for a term of one year and serve until their successors are duly elected and qualified. All executive officers hold office until their successors are duly appointed and qualified.
JOHN F. BOOKOUT joined Kelley Oil as Chairman of the Board, President and Chief Executive Officer in February 1996. He served as Chairman of the Board of Contour Production Company L.L.C. ("Contour") since its inception in 1993. From 1988 through 1993, he served as a member of the Supervisory Board of Royal Dutch Petroleum. He currently serves on the board of directors of McDermott International Inc., J. Ray McDermott, S.A. and The Investment Company of America as well as the board of trustees of the United States Counsel for International Business and various civic and educational bodies.
DAVID C. BAGGETT was elected Senior Vice President and Chief Financial Officer and a director of Kelley Oil in March 1997. Previously, he was a partner with Deloitte & Touche LLP for more than five years.
DALLAS D. LAUMBACH has served as Senior Vice President-Exploration and Production and a director of Kelley Oil since February 1996 and has served concurrently as President of Concorde Gas, Inc. since August 1996. He previously served as Senior Vice President of Contour commencing in December 1993. Before joining Contour, Mr. Laumbach served in positions of increasing responsibility for 24 years at Shell Oil Company, concluding as Manager-Business Development in Shell's Head Office.
THOMAS E. BAKER is an attorney and joined Kelley Oil in July 1996 as General Counsel and Corporate Secretary. From August 1991 through June 1996, Mr. Baker was engaged in a private consulting practice.
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, 1996 with respect to the only person known by the Partnership to own beneficially more than five percent of the Partnership's Units.
AMOUNT & NATURE NAME AND ADDRESS OF OF BENEFICIAL PERCENT BENEFICIAL OWNER OWNERSHIP OF CLASS - ------------------- --------------- -------- Kelley Oil Corporation 19,163,889 91.85% 601 Jefferson, Suite 1100 Direct Houston, Texas 77002
MANAGEMENT
The following table sets forth information as of December 31, 1996 with respect to Units beneficially owned, directly or indirectly, by each of the directors of Kelley Oil and by all officers and directors of Kelley Oil as a group.
AMOUNT & NATURE NAME AND ADDRESS OF OF BENEFICIAL PERCENT BENEFICIAL OWNER OWNERSHIP(1) OF CLASS - ------------------- --------------- -------- John F. Bookout -- -- Dallas D. Laumbach -- -- David C. Baggett -- -- All directors and officers as a group (9 persons) 1,000 .01% - ------------ (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 $2,580,897 to the Partnership for their 3.96% interest.
Kelley Oil is reimbursed for its direct costs and an allocable portion of its general and administrative expenses incurred as Managing General Partner. During 1994, 1995 and 1996, reimbursements of $2,496,000, $2,649,000 and $1,245,000, respectively, were made for costs directly associated with the Partnership's development drilling activities and $52,000, $542,000 and $753,000, respectively, for Kelley Oil's general and administrative expenses attributable to the operations of the Partnership. Costs and expenses incurred by Kelley Oil in connection with the syndication and organization
of the Partnership aggregating approximately $750,000 were reimbursed by the Partnership in 1994 and charged to partners' equity.
Kelley Partners advanced $1,879,000 on behalf of the Partnership prior to the closing of the Partnership's offering of Units to fund syndication costs and drilling activities. The entire amount of these advances, together with interest at a market rate, was repaid following the closing of the offering.
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: All 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:
EXHIBIT NUMBER: EXHIBIT ------- ------- 4.1 Amended and Restated Agreement of Limited Partnership of the Registrant (included as Exhibit A to the Prospectus forming part of the Registrant's Registration Statement on Form S-1 (File No. 33-72528) filed on December 7, 1993, as amended (the "Registration Statement") and incorporated herein by reference).
4.2 Joint Venture Agreement of Kelley Partners 1994 Development Drilling Joint Venture (incorporated by reference to Exhibit B to the Prospectus forming part of the Registration Statement).
(b) REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the fourth quarter of 1996.
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 27th day of March, 1997.
KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM
By: KELLEY OIL CORPORATION, Managing General Partner
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 27th day of March, 1997 by the following persons in their capacity as directors of the Registrant's managing general partner.
/s/ JOHN F. BOOKOUT /s/ DALLAS D. LAUMBACH John F. Bookout Dallas D. Laumbach
/s/ DAVID C. BAGGETT David C. Baggett