Exhibit 99.2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General
The following discussion is intended to assist in understanding our financial position and results of operations for each year of the three-year period ended December 31, 2000. Our financial statements and notes thereto contain detailed information that should be referred to in conjunction with the following discussion.
Proposed Restructuring and Acquisition. In January 2001, our majority stockholders organized a new corporation, Ascent Energy Inc., to acquire Pontotoc Production, Inc. Pursuant to that certain Agreement and Plan of Merger dated as of January 19, 2001, by and among Ascent Energy, Pontotoc Acquisition Corp. and Pontotoc Production, Inc. ("Pontotoc"), Ascent Energy has agreed to exchange $9.00 in cash and one share of its 8% Series B convertible preferred stock having a liquidation preference of $2.50 per share for each outstanding share of Pontotoc common stock (the "Offer"). Promptly following completion of the Offer, Ascent Energy intends to merge Pontotoc Acquisition Corp., its wholly owned subsidiary, with Pontotoc. Ascent Energy is obligated under the merger agreement to pay Pontotoc $2 million within five days of termination of the merger agreement if the termination is due to the failure of Ascent Energy to obtain financing and all other conditions to the Offer have been met. We have guaranteed this obligation.
On March 20, 2001, we acquired all the outstanding shares of Ascent Energy common stock from our majority stockholders in exchange for $1,000 cash. Concurrently with the consummation of the Offer, it is expected that we will be restructured as a holding company by contributing all of our assets and liabilities to Ascent Energy in exchange for additional shares of Ascent Energy common stock.
To help fund the Pontotoc acquisition, Ascent Energy plans to offer approximately $21.1 million of its 8% Series A Redeemable Preferred Stock and warrants to purchase shares of its common stock to our existing stockholders on a pro rata basis. Ascent Energy expects to obtain the remainder of the funds necessary to finance the Pontotoc acquisition from borrowings under a new credit facility that it is currently negotiating with its primary lender and from its internal resources.
Upon the closing of the Pontotoc acquisition, Ascent expects to have outstanding 21,100 shares of Series A preferred stock with a liquidation preference of $21.1 million, 5.3 million shares of Series B preferred stock with a liquidation preference of $13.3 million and term debt of approximately $30 million. The credit agreement will be secured by substantially all of our assets, which will be contributed to Ascent Energy concurrently with the consummation of the Offer.
Plan of Reorganization.Our Bankruptcy Plan was confirmed by the Bankruptcy Court on December 29, 1999 and consummated effective January 14, 2000. As of the confirmation date, we had total assets of $33.9 million and liabilities of $96.0 million. Except as described herein, all of our liabilities as of the confirmation date were extinguished pursuant to the Bankruptcy Plan. Pursuant to the Bankruptcy Plan, we issued an aggregate of approximately $3.6 million of promissory notes to general unsecured creditors and paid approximately $300,000 to holders of convenience claims. All disputed claims related to the bankruptcy have been resolved and, by order entered on December 9, 2000, a final decree was entered that closed the bankruptcy case.
Fresh Start Reporting.We have accounted for the reorganization by using the principles of fresh start accounting required by AICPA Statement of Position 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code." For accounting purposes, we assumed that the Bankruptcy Plan was consummated on December 31, 1999. Under the principles of fresh start accounting, our total assets were recorded at their assumed reorganization value, with the reorganization value allocated to identifiable tangible assets at their estimated fair value. Accordingly, our oil and gas full cost pool was reduced by approximately $60 million, our unevaluated oil and gas properties were increased by approximately $3 million, our other property and equipment was reduced by approximately $1.6 million, and our accumulated DD&A of $64.1 million was written off. In addition, our senior notes payable of $70 million, the interest payable of $11.1 million on the senior notes, our preferred stock of $13.5 million and the related deferred financing costs of $4.4 million were all written off.
The total reorganization value assigned to our proved oil and gas properties was estimated by adjusting the net pre-tax future cash flows discounted at a 10% annual rate (PV-10) of our proved reserves ($36.4 million) as set forth in the Estimate of Reserves and Future Revenue report on our proved oil and gas properties as of December 31, 1999, prepared by Netherland, Sewell & Associates. This report was prepared in accordance with SEC guidelines, utilizing constant prices existing as of December 31, 1999. We adjusted these prices to reflect the product prices used in valuing producing properties, and then we applied risking factors to the various categories of proved properties, discounting the properties as indicated:
Proved Category | Risk Factor |
Proved Producing | 95% |
Proved Non-producing | 75% |
Proved Undeveloped | 25% |
Applying these risk factors and adjusting the product pricing resulted in an estimated net realizable value of the PV-10 of the proved properties of $25.5 million. Our other assets, including other property and equipment, were valued at $4.9 million. As a result of the implementation of fresh start accounting, our financial statements after consummation of the Bankruptcy Plan are not comparable to our financial statements of prior periods.
The effect of the Bankruptcy Plan and the implementation of fresh start accounting on our balance sheet as of December 31, 1999 are discussed in detail in "Item 8. Financial Statements and Supplementary Data."
Operating Environment
Our revenues, profitability and future growth and the carrying value of our oil and natural gas properties are substantially dependent on prevailing prices of oil and natural gas. Our ability to increase our borrowing capacity and to obtain additional capital on attractive terms is also influenced by oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuation in response to relatively minor changes in the supply of or demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Any substantial and extended decline in the price of oil or natural gas would have an adverse effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. Price volatility also makes it difficult to budget for and project the return on either acquisitions or development and exploitation projects.
We use the full cost method of accounting for our investment in oil and natural gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves are capitalized into a ''full cost pool'' as incurred, and properties in the pool are depleted and charged to operations using the future gross revenue method based on the ratio of current gross revenue to total proved future gross revenues, computed based on current prices. To the extent that such capitalized costs (net of accumulated depreciation, depletion and amortization) less deferred taxes exceed the present value (using a 10% discount rate) of estimated future net cash flow from proved oil and natural gas reserves, and the lower of cost and fair value of unproved properties after income tax effects, excess costs are charged to operations. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date even if oil or natural gas prices increase. We were required to write down our asset base at the end of 1997 due to a downward revision of quantity estimates attributable to a single fault block in the Lake Enfermer Field, combined with significant declines in oil and natural gas prices from the end of 1996. During the second quarter of 1998, we were required to write down our asset base, again due primarily to the continuing decline in oil and natural gas prices. We had an additional full cost ceiling writedown of our asset base at the end of 1998. This writedown was the result of a significant revision to the reserves assigned to a single well in the Lake Enfermer Field, combined with further declines in both oil and natural gas prices during the final quarter of 1998. Lastly, we reduced our full cost pool in 1999 in connection with our bankruptcy.
Results of Operations
The following table sets forth certain operating information with respect to our oil and natural gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See "Item 2. Properties - Natural Gas and Oil Reserves."
Year Ended December 31, | |||||
2000 | 1999 | 1998 | |||
Production: | |||||
Oil (MBbls) | 270 | 343 | 393 | ||
Gas (MMcf) | 1,797 | 3,091 | 4,944 | ||
Oil and gas (MBOE) | 569 | 859 | 1,217 | ||
Sales data (in thousands): | |||||
Total oil sales | $ 7,421 | $ 5,954 | $ 4,752 | ||
Total gas sales | $ 7,276 | $ 7,038 | $ 11,198 | ||
Average sales prices: | |||||
Oil (per Bbl) | $ 27.49 | $ 17.34 | $ 12.09 | ||
Gas (per Mcf) | $ 4.05 | $ 2.28 | $ 2.27 | ||
Per BOE | $ 25.81 | $ 15.13 | $ 13.11 | ||
Average costs (per BOE): | |||||
Lease operating expenses | $ 5.89 | $ 3.66 | $ 2.76 | ||
General and administrative | $ 4.67 | $ 3.51 | $ 2.28 | ||
Depreciation, depletion and amortization | $ 7.87 | $ 6.52 | $ 8.58 | ||
Reserves at December 31: | |||||
Oil (MBbls) | 2,667 | 1,612 | 1,531 | ||
Gas (MMcf) | 26,260 | 18,996 | 14,558 | ||
Oil and gas (MBOE) | 7,044 | 4,778 | 3,957 | ||
Present value of estimated pre-tax future | $182,313 | $36,440 | $19,169 | ||
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Our oil and gas revenues increased approximately $1.7 million, or 13% during 2000 to $14.7 million compared to $13.0 million in 1999. Production levels for 2000 decreased 33.7% to 569 thousand barrels of oil equivalent (''MBOE'') from 859 MBOE for 1999. Gas production volumes decreased 41.9%, while oil production volumes decreased 21.4%. Our average sale prices (including hedging activities) for oil and natural gas for 2000 were $27.49 per Bbl and $4.05 per Mcf versus $17.34 per Bbl and $2.28 per Mcf in 1999. Revenues increased $5.9 million due to higher oil and gas prices during 2000, offset by a $4.2 million decrease in revenues due to the aforementioned production decreases.
On a BOE basis, lease operating expenses increased 60.7%, to $5.89 per BOE for 2000 from $3.66 per BOE in 1999. For 2000, actual lease operating expenses were up 6.6%, from $3.1 million in 1999 to $3.4 million in 2000. This increase was due primarily to an increase in workover activity in 2000.
Our effective severance tax rate as a percentage of oil and gas revenues decreased to 4.4% for 2000 from 5.6% for 1999. This relatively low effective rate is attributable to the increased production from wells that have a state severance tax exemption under Louisiana's severance tax abatement program. The decreases in the effective tax rates between 1999 and 2000 are partially offset by the increase in the gas severance tax rate in 2000.
For 2000, depreciation, depletion and amortization (''DD&A'') expense decreased 19.9% from 1999. The decrease for the year is attributable to our decreased production and related future capital costs in 2000 and the upward revision of reserves. On a BOE basis, which reflects the decreases in production, the DD&A rate for 2000 was $7.87 per BOE compared to $6.52 per BOE for 1999, an increase of 21%. The increase in DD&A per BOE was due primarily to an increase in the full cost pool and variations in pricing during the year. Reserve additions as of December 31, 2000, affected only the fourth quarter DD&A calculation.
For 2000, on a BOE basis, general and administrative (''G&A'') expenses increased 32.9%, from $3.51 per BOE in 1999 to $4.67 in 2000. The increase in G&A per BOE in 2000 was due to the decrease in production during 2000 as compared to 1999. Actual G&A expenses decreased 11.8%, from $3.0 million in 1999 to $2.7 million in 2000. The decrease in actual G&A expenses for 2000 was primarily the result of the capitalization of G&A expenses, in the amount of $842,391, into the full cost pool in 2000. No G&A was capitalized into the full cost pool for 1999 due to the bankruptcy and lack of funds to conduct acquisition and exploration activities. Without this capitalization of G&A in 2000, G&A on a BOE basis increased 75%, to $6.14 in 2000. Actual G&A in 2000, without the capitalization in 2000, increased $485,000 primarily due to income and franchise taxes, the addition of directors' fees and increases in contract services related to the appointment of our new president in June 2000. The recapitalization costs incurred in conjunction with our reorganization of $899,000 were not included in recurring G&A for comparison purposes.
The discounted present value of our reserves increased 500%, from $36.4 million at the end of 1999 to $182 million at the end of 2000, primarily as a result of the significant increases in both oil and gas prices between December 1999 and December 2000, combined with the new reserves attributable to workovers and recompletions of wells in our Boutte and Lake Enfermer Fields. Our realized oil prices increased 58.6% between December 31, 1999 and December 31, 2000, from an average price per barrel of $17.34 for 1999 to an average price of $27.49 for 2000. Our realized gas prices in 2000 increased 77.8% over the realized 1999 price, from an average price per Mcf of $2.28 for 1999 to an average price per Mcf of $4.05 for 2000.
Interest expense for 2000 decreased from $6.2 million in 1999 to $0 for 2000. Actual interest expense of $274,000 was incurred in 2000 but was capitalized into the unevaluated property within the full cost pool for reporting purposes. This decrease of $5.9 million in interest expense is due to the cessation of interest payable on our senior notes, which were canceled as a result of the reorganization effective January 14, 2000.
Due to the factors described above, our net income from operations before extraordinary items for 2000 was $1.7 million, an increase of $2.1 million from the net loss of $349,405 for 1999.
We were required to establish a net deferred tax liability calculated at the applicable Federal and state tax rates resulting primarily from financial reporting and income tax reporting basis differences in oil and gas properties. Accordingly, as a result of fresh start accounting a net deferred tax liability of $9.9 million was recorded at December 31, 1999.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Our oil and gas revenues decreased approximately $2.9 million, or 18% during 1999 to $13.0 million compared to $16.0 million in 1998. Production levels for 1999 decreased 29% to 859 MBOE from 1,217 MBOE for 1998. Gas production volumes decreased 37.5%, while oil volumes decreased 12.7%. Our average sale prices (including hedging activities) for oil and natural gas for 1999 were $17.34 per Bbl and $2.28 per Mcf versus $12.09 per Bbl and $2.27 per Mcf in 1998. Revenues decreased $5.2 million due to the aforementioned production decreases, offset by a $2.3 million increase in revenues due to higher oil and gas prices during 1999.
On a BOE basis, lease operating expenses increased 32%, to $3.66 per BOE for 1999 from $2.76 per BOE in 1998. For 1999, actual lease operating expenses were down 8.8%, from $3.4 million in 1998 to $3.1 million in 1999. This decrease was due to a decrease in 1999 in the volumes of oil and gas produced.
For 1999, DD&A expense decreased 47% from 1998. The decrease for the year is attributable to our decreased production and related future capital costs in 1999 and the upward revision of reserves. On a BOE basis, which reflects the decreases in production, the DD&A rate for 1999 was $6.52 per BOE compared to $8.58 per BOE for 1998, a decrease of 24%.
For 1999, on a BOE basis, G&A expenses increased 53%, from $2.28 per BOE in 1998 to $3.51 in 1999. Actual G&A expenses increased 8.6%, from $2.8 million in 1998 to $3.0 million in 1999. This increase was due primarily to the administrative costs of the reorganization activity during 1999. The recapitalization costs incurred in conjunction with reorganization of $1,184,000 were not included in recurring G&A for comparison purposes.
The discounted present value of our reserves increased 90%, from $19.2 million at the end of 1998 to $36.4 million at the end of 1999, primarily as a result of the new reserves attributable specifically to the Simoneaux 26 well in our Boutte Field, combined with the significant increases in both oil and gas prices between December 1998 and December 1999. Our realized oil prices increased 43% between December 31, 1998 and December 31, 1999, from an average price per barrel of $12.09 on December 31, 1998 to an average price of $17.34 on December 31, 1999. Our realized gas prices on December 31, 1999 increased 0.4% over the December 31, 1998 price, from an average price per Mcf of $2.27 in 1998 to an average price per Mcf of $2.28 in 1999. We experienced a $19.6 million writedown of our full cost pool during 1998 due to ceiling test limitations. We did not experience any such ceiling test writedown of our full cost pool in 1999.
Interest expense for 1999 decreased from $10.1 million in 1998 to $6.2 million for 1999. This decrease of $3.9 million in interest expense is due to the cessation of interest payable on our senior notes from August 6, 1999, the date we filed for protection under the United States Bankruptcy Code.
Due to the factors described above, the net loss from operations before reorganization costs and extraordinary items decreased from $30.5 million for 1998 to a loss of $0.3 million for 1999.
Liquidity and Capital Resources
Working Capital and Cash Flow.At December 31, 2000, we had $4.7 million of working capital compared to $1.7 million at December 31, 1999. This was primarily due to the significant increase in oil and, more significantly, natural gas prices during 2000. During 2000, we completed five recompletion/workover projects, of which all five were successful. We did not drill any wells in 2000.
We believe that our cash on hand plus expected normal cash flow from operations will be sufficient to fund our capital expenditure plans for development and exploitation activities for 2001 and our obligations on the long term notes payable issued pursuant to the Bankruptcy Plan. In addition, we will continue to pursue farm-in or joint venture partners for drilling prospects on our existing properties. The amount of capital expenditures for these drilling prospects will depend on the participation by other working interest owners, the availability of capital and other industry conditions.
The foregoing discussion includes many forward looking statements which are subject to the risks and uncertainties noted above in "Item 1 - Cautionary Statements" which could cause the actual results to differ materially from our expectations.
Hedging Activities.With the objective of achieving more predictable revenues and cash flows and reducing our exposure to fluctuations in oil and natural gas prices, we have entered into hedging transactions of various kinds with respect to both oil and natural gas. While the use of these hedging arrangements limits the downside risk of reverse price movements, it may also limit future revenues from favorable price movements. During 1998 and 1999, we entered into forward sales arrangements with respect to a portion (between 30-50%) of our estimated natural gas sales. As of March 2001, we had no open forward sales arrangements for natural gas for 2001. We did hedge 200 barrels per day of our oil production in October 1999 for the twelve months ending November 30, 2000, at a price of $22.05 per barrel.
We plan to continuously reevaluate our hedging program in light of market conditions, commodity price forecasts, capital spending and debt service requirements. We may hedge additional volumes into 2001 or we may determine from time to time to terminate our then existing hedging positions.
New Accounting Standards
The Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1997. This statement establishes accounting and reporting standards for derivative instruments and hedging activities. According to Statement No. 133, we must recognize the fair value of all derivative instruments as either assets or liabilities in our consolidated balance sheet. A derivative instrument meeting certain conditions may be designated as a hedge of a specific exposure. Accounting for changes in a derivative's fair value will depend on the intended use of the derivative and the resulting designation. Any transition adjustments resulting from adopting this statement will be reported in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. As described under the heading "Quantitative and Qualitative Disclosures About Market Risk" below, we may make use of derivative instruments to hedge specific market risks. We adopted Statement No. 133 on January 1, 2001. Because of the nature of our hedging activities, the adoption of Statement No. 133 did not have a material impact on our financial position or results of operations.
Quantitative and Qualitative Disclosures About Market Risk
Hedging Activity
Our revenues are derived from the sale of oil and natural gas production. From time to time, we enter into hedging transactions that fix, for specific periods and specific volumes of production, the prices we will receive for our production. These agreements reduce our exposure to decreases in the commodity prices on the hedged volumes, while also limiting the benefit we might otherwise have received from increases in commodity prices of the hedged production. The impact of hedges is recognized in oil and gas sales in the period the related production revenues are accrued. See "Item 1. Cautionary Statements - Our use of hedging transactions for a portion of our oil and gas production may limit future revenues from price increases and result in significant fluctuations in our stockholders' equity".
Despite the measures we may take to attempt to control price risk, we will remain subject to price fluctuations for oil and natural gas sold in the spot market. Prices received for natural gas sold in the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Oil and natural gas prices can change dramatically primarily as a result of the balance between supply and demand. The trend since 1998 has been upward, with our average natural gas price received for 2000 of $4.05 per Mcf, up from $2.28 per Mcf in 1999 and $2.27 per Mcf in 1998. Our average oil price received for 2000 was $27.49 per Bbl, up from our average price received of $17.34 in 1999 and $12.09 in 1998. There can be no assurance that prices will not decline from current levels. Declines in domestic oil and natural gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.
Based on projected annual production volumes for 2001, a 10% decline in the prices we receive for our oil and natural gas production would have an approximate $21.6 million negative impact on our discounted future net revenues.
