MANAGING GROWTH IN A
VOLATILE ENVIRONMENT

                                                   1998 ANNUAL REPORT

Management's Discussion and Analysis of
Financial Condition and Results of Operations 

 

The following discussion should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto.

General

The Company’s principal corporate objectives are the accumulation of crude oil and natural gas reserves for production and sale and the enhancement of the net present value of those reserves. Commencing in 1991, the Company began to emphasize the addition of reserves through increased development and exploration drilling activity. This emphasis on development and exploration drilling has led to additions of reserves in excess of the Company's production in each of the years 1996, 1997, and 1998. The Company’s revenues are primarily comprised of oil and gas sales attributable to properties in which the Company owns a direct or indirect interest.

Proved Oil and Gas Reserves. At year-end 1998, the Company’s total proved reserves were 436.1 Bcfe with a PV-10 Value of $340.8 million. In 1998, the Company’s proved natural gas reserves increased 38.1 Bcf (12%) and its proved oil reserves increased 6,099,007 barrels (78%) for a total of 74.7 Bcfe (21%). From 1996 to 1997, the Company’s proved natural gas reserves increased 88.5 Bcf (39%) and its proved oil reserves increased 2,374,609 barrels (43%) for a total of 102.8 Bcfe (40%). The Company’s additions to proved reserves from its development and exploration program were 73.9 Bcfe in 1998, 120.2 Bcfe in 1997, and 118.2 Bcfe in 1996. The Company’s additions to proved reserves from acquisitions were 97.6 Bcfe in 1998, 33.8 Bcfe in 1997, and 3.3 Bcfe in 1996. A substantial portion of these reserves are proved undeveloped reserves comprising 45% of total proved reserves at year-end 1998, 40% of total proved reserves at year-end 1997, and 39% of total proved reserves at year-end 1996.

The change in the Standardized Measure of Discounted Future Net Cash Flows (see Supplemental Information to the Company’s financial statements) and in the Estimated Present Value of Proved Reserves (see Business and Properties – Oil and Gas Reserves) from year-end 1997 to year-end 1998 is due to the addition of reserves through the Company’s drilling activity (primarily in the AWP Olmos Field and the Austin Chalk trend) and the purchases of minerals in place (primarily in the Austin Chalk trend with the Toledo Bend Properties acquisition), offset by revisions of previous estimates and by the 20% decrease in year-end 1998 natural gas prices ($2.23 per Mcf at year-end 1998 versus $2.78 per Mcf at year-end 1997), and to the 29% decrease in year-end 1998 oil prices ($11.23 per Bbl at year-end 1998, compared to $15.76 per Bbl the prior year). While the Company’s total proved reserves quantities at year-end 1998 increased by 21% over those at year-end 1997, the PV-10 Value of those reserves decreased 3% over the same period almost entirely due to pricing declines during 1998.

Under SEC guidelines, the Company’s estimates of proved reserves are made using oil and gas sales prices in effect at year-end and are held constant throughout the life of the properties. The $2.23 per Mcf and the $11.23 per barrel prices used to calculate the PV-10 Value were year-end 1998 prices, which may not be indicative of future sales prices ultimately received.

Liquidity and Capital Resources

Net Cash Provided by Operating Activities. In 1998, 1997, and 1996, the Company’s operating activities provided net cash of $54.2 million, $55.3 million, and $37.1 million, respectively. The slight decrease of $1.1 million in 1998 was primarily due to the 54% increase in production volumes being more than offset by (a) the 25% decrease in average commodity prices received, (b) the associated 50% increase in oil and gas production costs, and (c) a decrease in interest income and an increase in interest expense as a result of all the net proceeds of the $115.0 million Convertible Notes offering having been expended during 1997 and increased bank borrowings occurring during 1998. The 1997 increase of $18.2 million was primarily due to an increase of $16.5 million in cash flows from oil and gas sales and interest income.

Existing Credit Facilities. At December 31, 1998, the Company had outstanding borrowings of $146.2 million under its new credit facility syndicated in August 1998. At December 31, 1997, the Company had $7.9 million outstanding under its borrowing arrangements. Currently, the new credit facility consists of a $250.0 million revolving line of credit with a $170.0 million borrowing base. The borrowing base is redetermined at least every six months. The Company’s $250.0 million revolving credit facility includes, among other restrictions, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios) and limitations on incurring other debt. The Company is currently in compliance with the provisions of this agreement, as amended in mid-March 1999 to modify the cash flow-to-debt covenant. The New Credit Facility will extend until August 2002.

Working Capital. The Company’s working capital has increased from $1.5 million at December 31, 1997, to $3.8 million at December 31, 1998. This increase is primarily the result of an increase in oil and gas sales receivables resulting from the Company’s increase in production volumes.

Due to the nature of the Company’s business highlighted above, the individual components of working capital fluctuate considerably from period to period. The Company incurs significant working capital requirements in connection with its role as operator of approximately 836 wells and its drilling and acquisition activities. In this capacity, the Company is responsible for certain day-to-day cash management, including the collection and disbursement of oil and gas revenues and related expenses.

Capital Expenditures. The Company’s capital expenditures were approximately $183.8 million, $132.0 million, and $91.5 million for 1998, 1997, and 1996, respectively. The 1998 capital expenditures included (a) $59.5 million (32% of 1998 capital expenditures) spent on producing properties acquisitions (almost all of which was for the Toledo Bend Properties acquisition), (b) $54.8 million (30%) on developmental drilling (primarily in the AWP Olmos Field and Austin Chalk trend), (c) $12.6 million (7%) on exploratory drilling, (d) $34.7 million (19%) on domestic prospect costs (principally leasehold, seismic, and geological costs of unproven prospects for the Company’s account, including $15.2 million for leaseholds in the Toledo Bend Properties acquisition), (e) $15.0 million (8%) for the purchase of gas processing plants in the Toledo Bend Properties acquisition, (f) $3.9 million (2%) invested in foreign business opportunities in New Zealand ($2.9 million), Venezuela ($0.4 million), and Russia ($0.6 million), as described in Note 8 to the Company’s financial statements, (g) $2.2 million (1%) on field compression facilities, and (h) $1.0 million (1%) on fixed assets.

In 1998, the Company participated in drilling 75 wells (61 development wells and 14 exploratory with 53 development successes and 5 exploratory successes). The steady growth in the Company’s unproved property account ($56.0 million), which is not being amortized, is indicative of the shift to a focus on drilling activity in recent years as the Company has acquired prospect acreage in or near its core areas (such as the acquisition of substantial leasehold positions in the Toledo Bend Properties acquisition) and in the pursuit of its New Zealand activities.

Sources and Uses of Funds. During 1997, the Company relied upon net proceeds from the sale of its $115.0 million of Convertible Notes and its internally generated cash flows, along with $7.9 million of bank borrowings to fund capital expenditures. During 1998, the Company relied upon $138.3 million of bank borrowings, along with its internally generated cash flows of $54.2 million, to fund its capital expenditures of $183.8 million. Cash and working capital for 1999 are expected to be provided primarily through internally generated cash flows and limited bank borrowings.

Capital expenditures for 1999 are estimated to be substantially lower at approximately $54.2 million. Approximately $36.0 million of the 1999 budget is allocated to development and exploration drilling, primarily in its two core areas. The Company anticipates drilling 20 wells (15 development and five exploratory) in 1999. The remaining $18.2 million is targeted principally for leasehold, seismic, and geological costs of unproved properties.

The Company believes that 1999’s anticipated internally generated cash flows, together with limited borrowings under the new credit facility, will be sufficient to finance the costs associated with its currently budgeted 1999 capital expenditures.

Results of Operations

 

Revenues. The Company’s revenues in 1998 increased by 10% over revenues in 1997 and by 32% in 1997 over 1996 revenues, principally due to increases in oil and gas sales revenues.

The Company’s net sales volumes in 1998 (including the volumetric production payment associated with each year’s production) increased by 54% (13.6 Bcfe) over net sales volumes in 1997, while 1997 net sales volumes increased by 31% (6.0 Bcfe) over net sales volumes in 1996. Oil and gas sales revenues in 1998 increased by 16% ($11.1 million) over those revenues for 1997, while in 1997 those revenues increased by 31% ($16.2 million) over oil and gas sales revenues in 1996. Average prices for oil have declined from $19.82 per Bbl in 1996 to $17.59 per Bbl in 1997 to $11.86 per Bbl in 1998, while average gas prices increased slightly from $2.57 per Mcf in 1996 to $2.68 per Mcf in 1997 and then decreased to $2.08 per Mcf in 1998.

In 1998, the elements of the Company’s $11.1 million increase in oil and gas sales included (a) volume increases that added $18.4 million of sales from the 6.9 Bcf increase in gas sales volumes and $19.9 million of sales from the 1.1 million barrel increase in oil sales volumes and (b) price variances that had a $27.2 million unfavorable impact on sales due to the 22% decrease in average gas prices received ($16.9 million), and the 33% decrease in average oil prices received ($10.3 million).

In 1997, the Company’s $16.2 million increase in oil and gas sales included (a) volume increases that added $14.5 million of sales from the 5.7 Bcf increase in gas sales volumes and $1.0 million of sales from the 49,000 barrel increase in oil sales volumes, and (b) price variances that contributed $2.2 million in increased sales from the increase in average gas prices received, offset somewhat by a $1.5 million decrease in sales from the decrease in average oil prices received.

In 1998, the increases in oil and gas sales were primarily the result of production from the Toledo Bend Properties acquisition and secondarily from the Company’s scaled-down drilling program, most notably from the Austin Chalk trend. The decisions to make this acquisition and to defer some drilling were both in response to market conditions. In 1997, the increases in oil and gas sales were primarily the result of production from the Company’s accelerated drilling program, most notably from the Company’s two primary development areas, the AWP Olmos Field and the Austin Chalk trend. The Company’s 1998 oil and gas sales from the Toledo Bend Properties were $24.2 million (none in 1997) from 11.6 Bcfe of net sales volumes, while sales from the rest of the Austin Chalk trend were $14.6 million ($12.9 million in 1997) from 7.0 Bcfe of net sales volumes (4.9 Bcfe in 1997), for an increase of 2.1 Bcfe. Sales in 1998 from the AWP Olmos Field were $33.5 million ($42.2 million in 1997) from 15.5 Bcfe of net sales volumes in both 1998 and 1997.

Revenues from oil and gas sales comprised 97%, 92%, and 94%, respectively, of total revenues for 1998, 1997, and 1996. The majority (73%, 83%, and 77%, respectively) of these oil and gas revenues in these periods were derived from the sale of the Company’s gas production. The Toledo Bend Properties acquisition, which has a higher percentage of its production from oil (56% of 1998 production), has somewhat altered the Company’s predominate gas production mix. Even though the Company has scaled back its 1999 capital expenditures budget, the Company expects oil and gas sales volumes to increase in 1999 when compared to 1998, primarily due to the full year of production from the Toledo Bend Properties. However, to the extent the Company curtails its development and exploration program as a result of the continued low price environment, oil and gas sales volumes will likely decrease in years subsequent to 1999.

Costs and Expenses. General and administrative expenses in 1998 increased $0.3 million (9%) from the level of such expenses in 1997, while 1997 general and administrative expenses decreased $0.6 million (15%) over 1996 levels. The small variances in these costs over the three-year period reflect the Company’s ability to continue increasing its activities and reserves base without materially increasing such costs. The Company’s general and administrative expenses per Mcfe produced have decreased in each of the past three years from $0.21 per Mcfe produced in 1996 to $0.14 per Mcfe produced in 1997 to $0.10 per Mcfe produced in 1998. Supervision fees netted from general and administrative expenses for 1998, 1997, and 1996 were $2.7 million, $2.6 million, and $2.2 million, respectively.

Depreciation, depletion, and amortization ("DD&A") has steadily increased (62% in 1998 and 47% in 1997), primarily due to the Company’s reserves additions and associated costs and to the related sale of increased quantities of oil and gas produced therefrom (54% in 1998 and 31% in 1997). The Company’s DD&A rate per Mcfe of production was $0.85 in 1996, $0.95 in 1997, and $1.01 in 1998, reflecting variations in the per unit cost of reserves additions.

Production costs in 1998 increased $4.4 million (50%) over such expenses in 1997, while those expenses in 1997 increased $2.6 million (43%) over 1996 costs. The increases in each of the periods primarily relate to the increases in the Company’s oil and gas sales volumes. The Company’s production costs per Mcfe produced were $0.34 in 1998, $0.35 in 1997, and $0.32 in 1996. Supervision fees netted from production costs for 1998, 1997, and 1996 were $2.7 million, $2.6 million, and $2.2 million, respectively.

Interest expense in both 1998 and 1997 on the Notes, including amortization of debt issuance costs, totaled $7.5 million, compared to $0.7 million on the Notes and $1.0 million on the Debentures in 1996, while interest expense on the credit facilities, including commitment fees, in 1998 totaled $5.6 million ($0.1 million in 1997 and $1.1 million in 1996), for a 1998 total interest expense of $13.1 million (of which $4.4 million was capitalized). The 1997 total interest expense was $7.6 million (of which $2.6 million was capitalized), while the 1996 total interest expense was $2.8 million (of which $2.1 million was capitalized). The Company capitalizes that portion of interest related to its exploration, partnership, and foreign business development activities. The increase in interest expense in 1998 was attributable to the increase in interest incurred on the amounts outstanding on its existing credit facility. The increase in interest expense in 1997 was attributable to the larger outstanding principal amount on the Notes ($115.0 million) compared to the Debentures ($28.75 million), offset to some degree by larger outstanding balances under the Company’s credit facilities in 1996 and by the $2.4 million in interest income earned in 1997 on the portion of the net proceeds of the Notes invested pending use.

A non-cash write-down of oil and gas properties occurred during the third quarter of 1998, as discussed in Note 1 to the Company’s financial statements. Lower prices for both oil and natural gas at September 30, 1998, necessitated a pre-tax domestic full-cost ceiling write-down of $77.2 million ($50.9 million after tax). Concurrently, in the third quarter, the Company re-evaluated the timing of the recovery of its capitalized unproved properties costs in Russia due to economical and political uncertainty and impaired its total investment of $10.8 million. In addition, the international economic uncertainty and currency concerns in Venezuela, combined with the price volatility and severe tightening of international credit markets, also caused the Company to impair its capitalized unproved properties costs in Venezuela of $2.8 million. The re-evaluation of the unproved properties costs in these two countries resulted in a separate non-cash pre-tax charge to earnings of $13.6 million ($9.0 million after tax). The combination of the non-cash full-cost ceiling write-down and the non-cash foreign impairment charges resulted in a combined non-cash pre-tax charge to earnings of $90.8 million ($59.9 million after tax).

The Company’s full-cost ceiling cushion at December 31, 1998, was approximately $25.0 million. If during 1999, oil and gas prices decrease appreciably from year-end 1998 prices, then the Company might be required to make another ceiling test write-down.

Net Income. Before the non-cash write-down of oil and gas properties in 1998, net income of $11.7 million and basic earnings per share of $0.71 were 48% and 47% lower, respectively, than net income of $22.3 million and basic earnings per share of $1.35 in the same period for 1997. This decrease primarily reflected the effect of the 33% and 22% decreases in oil and gas prices, respectively, while costs and expenses increased in proportion to the 54% increase in production volumes discussed above.

Net income of $22.3 million and basic earnings per share of $1.35 for 1997 were 17% and 6% higher, respectively, than net income of $19.0 million and basic earnings per share of $1.27 in 1996. This increase in net income primarily reflected the effect of a 31% increase in oil and gas sales revenues as a result of a 36% increase in natural gas production, an 8% increase in crude oil production, and a slight 4% increase in gas prices received, offset somewhat by an 11% decrease in oil prices received. The lower percentage increase in basic earnings per share reflects a 10% increase in weighted average shares outstanding in 1997 as a result of the conversion of the Debentures into 2.34 million shares of common stock in the third quarter of 1996.

Year 2000. The Year 2000 issue results from computer programs and embedded computer chips with date fields that cannot distinguish between the years 1900 and 2000. The Company is currently implementing the steps necessary to make the Company’s operations capable of addressing the Year 2000. These steps include upgrading, testing, and certifying its computer systems and field operation services and obtaining Year 2000 compliance certification from the Company’s critical business suppliers, customers, venders, and other service providers. The Company formed a task force during 1998 to address the Year 2000 issue and prepare the Company’s business systems for the Year 2000. By mid-1999 the Company expects the mission critical systems to be either replaced or updated and testing to be virtually completed.

The Company’s business systems are almost entirely comprised of off-the-shelf software. Most of the necessary changes in computer instructional code can be made by upgrading such software. The Company is currently in the process of either upgrading the off-the-shelf software or receiving certification as to Year 2000 compliance from vendors or third-party consultants. A testing phase is being conducted as the software is updated or certified and is expected to be completed by mid-1999.

The Company does not believe that costs incurred to address the Year 2000 issue with respect to its business systems will have a material effect on the Company’s results of operations or its liquidity and financial condition. The estimated total cost to address Year 2000 issues is projected to be less than $150,000, most of which will be spent during the testing phase.

The failure to correct a material Year 2000 problem could result in an interruption or failure of certain normal business activities or operations. Based on activities to date, the Company believes that it will be able to resolve any Year 2000 problems concerning its financial and administrative systems. It is undeterminable how all the aspects of the Year 2000 issue will impact the Company; however, field operations and the myriad of peripheral technical applications which perform the Company’s core business functions of oil and gas exploration are primarily non-information technology systems which are not date specific and are predicted to perform correctly. The most reasonably likely worst case scenario, therefore, would involve a prolonged disruption of external power sources upon which core equipment relies, resulting in a substantial decrease in the Company’s oil and gas production activities. Although the Company maintains limited on-site secondary power supplies such as generators, it is not economically feasible to maintain a secondary power supply to fully replace primary power; therefore, a prolonged interruption could materially affect the Company’s operations, liquidity or capital resources. In addition, pipeline operators to whom the Company sells natural gas, as well as other customers and suppliers, could be prone to Year 2000 problems that could not be assessed or detected by the Company. The Company is contacting its major purchasers, customers, suppliers, financial institutions and others with whom it conducts business to determine whether they will be able to resolve in a timely manner any Year 2000 problems directly affecting the Company and to inform them of the Company’s internal assessment of its Year 2000 review. There can be no assurance that such third parties will not fail to appropriately address their Year 2000 issues or will not themselves suffer a Year 2000 disruption that could have a material adverse effect on the Company’s business, financial condition, or operating results. Based upon these responses and any problems that arise during the testing phase, contingency plans or back-up systems would be determined and addressed. The Company has utilized, and will continue to utilize, both internal and external resources to complete tasks and perform testing necessary to address the Year 2000 problem.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. The Company’s major market risk exposure is the commodity pricing applicable to its oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of such pricing volatility have been discussed above, and such volatility is expected to continue.

To mitigate some of this risk, the Company engages periodically in certain limited hedging activities but only to the extent of buying protection price floors for portions of its and the Company managed limited partnerships’ oil and gas production. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any year presented. The costs to purchase put options are amortized over the option period. The Company does not hold or issue derivative instruments for trading purposes. The costs related to 1998 hedging activities totaled approximately $377,000, with benefits of approximately $101,000 being received, resulting in a net cash outlay of approximately $276,000 or $0.007 per Mcfe. The costs related to the open contracts totaled approximately $252,000 and had a market value of $267,000 as of December 31, 1998. The costs related to 1997 hedging activities totaled approximately $1,052,000 ($800,000 in 1996) with benefits of approximately $439,000 (none in 1996) being received, resulting in a net cash outlay of approximately $613,000 or $0.014 ($0.041 in 1996) per Mcfe.

Interest Rate Risk. The Company considers its interest rate risk exposure to be minimal as a result of a fixed interest rate on the $115,000,000 Convertible Notes. In regards to its New Credit Facility, the result of a 10% fluctuation in short-term interest rates (approximately 63 basis points) would impact 1999 cash flow by approximately $0.9 million.

Financial Instruments & Debt Maturities. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and convertible notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 1998 and 1997 and were determined based upon interest rates currently available to the Company for borrowings with similar terms. The fair values of the convertible notes were $81.4 million and $113.6 million at December 31, 1998 and 1997, respectively, and were based on quoted market prices as of the respective dates. Bank borrowings under the Company’s new credit facility mature on August 18, 2002. The Company’s $115.0 million convertible notes mature on November 15, 2006.

Forward Looking Statements

The statements contained in this Annual Report on Form 10-K ("Annual Report") that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, and therefore involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, Year 2000 issues, and competition. Such forward-looking statements generally are accompanied by words such as "plan," "budget," "estimate," "expect," "predict," "anticipate," "projected," "should," "believe," or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates, or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company, including those regarding the Company’s financial results, levels of oil and gas production or revenues, capital expenditures, and capital resource activities. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; competition and government regulations; as well as the risks and uncertainties discussed in this Annual Report, including, without limitation, the portions referenced above and the uncertainties set forth from time to time in the Company’s other public reports, filings, and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year.

 

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